Method and system for completing a well

ABSTRACT

Disclosed herein is a method of injecting a fluid into a subterranean formation, the method comprising: placing a first wellbore in the subterranean formation; injecting the fluid through the first wellbore into the subterranean formation at an injection rate of R1, wherein R1 is varied with time or fixed; subsequently injecting the fluid through the first wellbore into the subterranean formation at an injection rate of R2 for a duration of time D1, wherein R2 is varied with time or fixed; subsequently injecting the fluid through the first wellbore into the subterranean formation at an injection rate of R3, wherein R3 is varied with time or fixed.

CROSS-REFERENCE TO RELATED APPLICATIONS

This application claims the benefit under 35 U.S.C. § 119(e) of U.S. Provisional Patent Application No. 62/422,553 filed Nov. 15, 2016, the disclosure of which is hereby incorporated herein by reference in its entirety.

STATEMENT REGARDING FEDERALLY SPONSORED RESEARCH OR DEVELOPMENT

Not applicable.

FIELD OF THE INVENTION

Embodiments described herein relate to systems and methods for subsurface wellbore completion and subsurface reservoir technology. More particularly, embodiments described herein relate to systems and methods of preparing a wellbore for production.

BACKGROUND

In recent years, hydrocarbon production from lower permeability underground reservoirs has become more pervasive. These lower permeability formations are often called shale plays or tight-plays or ultra-tight plays or unconventional resources. They are often developed by drilling vertical or horizontal wells into the formation and then creating fractures in the rock to facilitate increased access to the hydrocarbons. The term fracturing is well known to someone skilled in the art, but it generally refers to the methods and processes for creating a fracture or breaking a subterranean formation. This can be done in many ways but is primarily done by injecting fluid into the formation through a wellbore penetrating the subterranean formation. The fluid is typically injected at high pressure, exceeding the parting pressure or breakdown pressure or minimum horizontal stress in at least a portion of the formation for at least a period of time.

Hydraulic fracturing techniques often involve injecting water and a combination of chemicals and sand into an underground reservoir or subterranean formation through the well to break or fracture the reservoir or subterranean formation and increase access to the reservoir to increase production of hydrocarbons or other fluids of value from a reservoir or subterranean formation. The hydraulic fracturing fluid or treatment fluid or injection fluid is typically pressurized by pumps and introduced through the wellbore into the formation, typically through a conventional hydraulic fracturing set-up or directly into the wellbore or through an injection tubing or a coil tubing or any known technique to one skilled in the art.

Completing these wells and making them ready for commercial production often includes the process of performing multiple hydraulic fracturing treatments in multiple stages or zones along the well. In each stage, there are typically multiple perforation clusters or perforated zones. However, even with long horizontal wells, which can extend over a mile with multiple stages and multiple clusters per stage, these plays often only see 5%-20% recovery of the original oil in place by primary depletion. One of the main challenges to increasing recovery and increasing recovery rates is the difficulty in gaining access to the entire reservoir. Hydraulic fracturing treatments may only create one or two or several fractures per stage, despite having many possible fracture initiation points along the well, which typically has multiple perforation clusters shot. With stages sometimes being longer than 50 feet or even longer than 250 feet, only a small number of fractures provide limited access. Moreover, in addition to the small number of fractures, even in the fractures created, a majority of the fluid in most stages is found to go into just one or two main fractures.

It has been observed that the distribution of the hydraulic fracturing fluid along a stage in a shale well can be often very poor. In some cases, it has been observed that in excess of 50% and sometimes in excess of 90% of the fluid or proppant injected into the stage may enter less than 40% and sometimes less than 10% of the perforation clusters. This poor conformance of the fluid and proppant results in slower recovery from the play than in the case of better conformance and can potentially result in a lower recovery factor from the reservoir. Both the hydraulic fractures themselves and the proppant may only be distributed in a small portion of the play. In addition, designing the optimal well spacing and number of stages can be very difficult, as the largest fractures in a given stage may overlap between two wells (covering the intra well area) while a vast majority of the fractures between two adjacent wells do not overlap, leaving space in the reservoir that will not be effectively produced because there are no proximal fractures through which to produce the fluids.

Moreover, many of the older wells completed with legacy stimulation techniques were under stimulated and have even poorer recovery factors. In some cases, only a single stage treatment was performed and in other cases, multiple stage hydraulic fracturing treatments were performed, but far fewer than the number of stages typically treated today, which can often exceed 30 stages, or 60 stages, or even 90 stages per well. To improve the recovery factor from wells that have been previously produced, wells can be restimulated or refractured. Refracturing can fracture new formation rock, providing access to previously unproduced or poorly produced formation. It can also restimulate existing fractures, enhancing production.

Refracturing a previously stimulated well can also help address another challenge that many operators face. Many acreage positions were developed by completing a single well in lease to hold the lease with plans to come back and drill and complete additional wells in the lease at a later point in time. These older wells, sometimes referred to as leasehold wells, parent wells, or legacy wells, are typically substantially depleted. When fluids are removed or produced from the subterranean formation (as occurs in the case of hydrocarbon production), the stress state in the depleted region is reduced. When a new well or child well is drilled and completed on the same lease in close enough proximity to the depleted stress zone, the fractures have a tendency to grow preferentially into the depleted zone, resulting in a poorer completion for the child well and thus poorer performance. To mitigate this effect and improve the completion and production performance of newly stimulated wells, legacy wells in proximity to new wells can be refractured to repressurize up the depleted stress zone. Legacy wells can also simply undergo low pressure fluid injection to repressurize the formation and alter the stress state in the depleted zone without fracturing the formation.

One of the chief challenges in effectively refracturing or repressurizing a well is achieving uniform fluid conformance along the lateral of the well. The original distribution of the fractures strongly influences the pressure distribution along the lateral, and thus can influence the distribution of fluid upon reinjection. In addition, some wells can be in excess of 1,000 feet, 5,000 feet, or 20,000 feet in measured depth. The length of the well in the subterranean formation can sometimes exceed 5,000 feet, 10,000 feet, or even 15,000 feet. During production, this can result in a non-negligible pressure drop along the well, which may result in preferential production from the heel portion of the well (the portion of the well closest to the wellhead). This can result in a lower pressure toward the heel of the well than toward the toe of the well, and upon reinjection a preferential path toward the heel of the well for fluid to enter the formation. Likewise upon reinjection, the pressure drop along the lateral can be significant, particularly at high rate, further exacerbating this preference for fluid to enter the heel of the well over the toe of the well.

One of the main challenges to increasing recovery and increasing recovery rates is the difficulty in gaining access to the entire reservoir. Hydraulic fracturing treatments may only create one or two or several fractures per stage, despite having many possible fracture initiation points along the well, which typically has multiple perforation clusters shot. With stages sometimes being longer than 50 feet or even longer than 250 feet, a small number of fractures only provides limited access. Moreover, in addition to the small number of fractures, even in the fractures created a majority of the fluid in most stages is found to go into just one or two main fractures. It has been observed that the distribution of the hydraulic fracturing fluid along a stage in a shale well can be often very poor. In some cases it has been observed that in excess of 50% and sometimes in excess of 90% of the fluid or proppant injected into the stage may enter less than 40% and sometimes less than 10% of the perforation clusters. This poor conformance of the fluid and proppant results slower recovery from the play than in the case of better conformance and can potentially result in a lower recovery factor from the reservoir. Both the hydraulic fractures themselves and the proppant may only be distributed in a small portion of the play. In addition, designing the optimal well spacing and number of stages can be very difficult, as the largest fractures in a given stage may overlap between two wells (covering the intra well area) while a vast majority of the fractures between two adjacent wells do not overlap (leaving space in the reservoir that will not be effectively produced because there are no proximal fractures through which to produce the fluids.

Many technologies have been explored in an attempt to improve hydraulic fracture fluid and proppant distribution along a well. Wellbore diverters (which are designed to physically block perforations during the fracturing process) and deep diverters (which are designed to pass through the perforations into the fractures to block them) are two of the most common types of methods for addressing poor fluid conformance during hydraulic fracturing. Diverters are injected during the fracturing process and have been shown to sometimes be effective at improving fluid distribution. However, many times they have little benefit and sometimes they even worsen the fluid distribution along the stage. Both wellbore diverters and deep diverters can block or prohibit fracture growth of some of the smaller fractures, which would often accelerate growth of larger fractures, thus making fluid conformance even worse. Other methods such as using different viscosity fluids or changing proppant loading have also been observed to impact fluid distribution along the well; however, these processes are complex, uncontrollable, and in many cases (especially with proppant changes) often worsen the fluid conformance along the well, impeding overall hydrocarbon production.

There are a number of techniques for assessing if diversion or other techniques are helping to improve fluid conformance along a well. One such method is installation of fiber optics along the well; however, this technology is very expensive and is often cost-prohibitive in practical use for such monitoring. Fiber optics is able to give insight into fluid and even proppant distribution along the well, but they are unable to give insight into fracture growth and proppant distribution in the fractures, as they are only taken at the well that is being stimulated. Fluids and proppant may pass by the fiber cable proportionally or disproportionally along a well, which does not necessarily correlate with fracture geometries and proppant distribution, which is what operators need to know and have control of. For instance, fiber optics could show a vast majority of fluid passing through the well near just a single cluster, but that fluid could be entering a fault, high-permeability channel, or natural fracture system and completely ineffective in stimulating new formation/rock. Moreover, fiber installed outside of the wellbore uses acoustics or thermal readings to infer fluid distribution, and lacks accuracy in measurement.

Another technique for evaluating diverter effectiveness and fluid distribution along a well during fracturing is monitoring the change in pressure in the well being stimulated. For instance, the pressure at the surface of the stimulated well immediately before the diverter hits the perforations can be compared with the pressure after the diverter hits the perforations. The magnitude of the pressure change before and after diversion interacts with the perforations can be related to the effectiveness of the diverter. However, it has been shown repeatedly that there is no correlation between the changes in pressure in the stimulated well before and after diverter lands and the effectiveness of diverter at improving fluid distribution along the well. The reason for this is if the diversion material blocks off any perforations in the well, at the same injection rate, the cross sectional area in the well for the fluid to pass through into the formation is reduced, so the pressure will always go up if any perforations are blocked. However, there is no ability to evaluate whether the right perforations are blocked off. If, for instance, the perforations corresponding to the smallest fractures were blocked off and more fluid was driven to the largest fracture, then that would make the fluid conformance along the well even worse, even though there may be a large change in pressure recorded in the stimulated wellbore after dropping diverter.

Clearly, there is continuing need and interest to develop systems and methods to enhance oil recovery in such lower permeability underground reservoirs.

SUMMARY

Herein disclosed is a method of injecting a fluid into a subterranean formation, the method comprising: (a) placing a first wellbore in the subterranean formation; (b) injecting the fluid through the first wellbore into the subterranean formation at an injection rate of R1, wherein the fluid enters the subterranean formation at a pressure greater than or equal to the minimum horizontal stress in at least a portion of the subterranean formation; (c) subsequently at a time T1 injecting the fluid through the first wellbore into the subterranean formation at an injection rate of R2, wherein the injection rate R2 is no greater than 50% of the injection rate R1 and no less than 5% of the injection rate R1; (d) subsequently injecting the fluid through the first wellbore into the subterranean formation at an injection rate less than or equal to R2 for a duration of time D1; (e) subsequently injecting the fluid through the first wellbore into the subterranean formation at an injection rate of R3, wherein the fluid enters the subterranean formation at a pressure greater than or equal to the minimum horizontal stress in at least a portion of the subterranean formation, wherein the injection rate R3 is no less than 150% of the injection rate R2.

In various embodiments, the fluid comprises water, gel, slickwater, hybrid fracturing fluid, viscosified aqueous fluid, acid, foam, carbon dioxide, nitrogen, hydrocarbon, polymer, sand, resin-coated proppant, ceramic proppant, proppant, or any combination thereof. In various embodiments, the method comprises changing the composition of the fluid. In various embodiments, the fluid does not comprise diverter material during step (d).

In various embodiments, the duration of time D1 is no less than 30 seconds, or no less than 5 minutes, or no less than 10 minutes, or no less than 30 minutes, or no greater than 3 hours. In various embodiments, steps (c)-(e) are repeated.

In various embodiments, the injection rate R1 is greater than or equal to 20 barrels per minute. In various embodiments, the injection rate R2 is greater than or equal to 1 barrels per minute.

In various embodiments, the first wellbore has two or more perforated zones. In various embodiments, the ratio of the rate of fluid injected into a first perforated zone over the rate of fluid injected into a second perforated zone is Rr and Rr is less than 1 during step (b), wherein Rr during step (e) is greater than Rr during step (b).

In various embodiments, the method comprises recovering hydrocarbons from the subterranean formation through the first wellbore. In various embodiments, the subterranean formation is selected from the group consisting of a low permeability formation, shale formation, tight formation, ultra-tight formation, hydrocarbon-bearing formation, oil reservoir, gas reservoir, hydrocarbon reservoir, and combinations thereof. In various embodiments, the subterranean formation is hydraulically fractured.

In various embodiments, the method comprises placing a second wellbore penetrating the subterranean formation and monitoring the second wellbore to determine time T1. In various embodiments, the fluid pressure in the second wellbore is measured. In various embodiments, at least a portion of the subterranean formation in contact with the second wellbore has been hydraulically fractured. In various embodiments, the fluid pressure in the second wellbore is measured using a wellhead pressure gauge, a downhole pressure gauge, a downhole retrievable pressure gauge, a downhole fiber optic gauge, or a downhole pressure gauge installed in a bridge plug. In an embodiment, the second wellbore is the first wellbore.

Also disclosed herein is a method of injecting a fluid into a subterranean formation, the method comprising: placing a first wellbore in the subterranean formation; injecting the fluid through the first wellbore into the subterranean formation at an injection rate of R1, wherein R1 is varied with time or fixed; injecting the fluid through the first wellbore into the subterranean formation at an injection rate of R2 for a duration of time D1, wherein R2 is varied with time or fixed and R2 is in the range of 5%-50% of the max of injection rate R1; injecting the fluid through the first wellbore into the subterranean formation at an injection rate of R3, wherein R3 is varied with time or fixed and wherein the max of injection rate R3 is no less than 150% of the minimum of injection rate R2. In various embodiments, the fluid enters the subterranean formation at a pressure greater than or equal to the minimum horizontal stress in at least a portion of the subterranean formation when the fluid is injected at injection rate of R1 or R3.

Further discussed herein is a non-transient computer-readable medium including instructions that, when executed by one or more processors, causes the one or more processors to perform a method, the method comprising: placing a first wellbore in the subterranean formation; injecting the fluid through the first wellbore into the subterranean formation at an injection rate of R1, wherein R1 is varied with time or fixed; injecting the fluid through the first wellbore into the subterranean formation at an injection rate of R2 for a duration of time D1, wherein R2 is varied with time or fixed and R2 is in the range of 5%-50% of the max of injection rate R1; injecting the fluid through the first wellbore into the subterranean formation at an injection rate of R3, wherein R3 is varied with time or fixed and wherein the max of injection rate R3 is no less than 150% of the minimum of injection rate R2.

Herein disclosed is a method of producing hydrocarbons from a subterranean formation, the method comprising: (a) placing a first wellbore in the subterranean formation; (b) injecting a first fluid through the first wellbore into the subterranean formation at a pressure equal to or greater than the minimum horizontal stress in at least a portion of the formation; (c) creating a hydraulic fracture in the subterranean formation; (d) subsequently producing hydrocarbons through the first wellbore for a duration of time D0; (e) subsequently injecting a second fluid through the first wellbore into the subterranean formation at an injection rate of R1; (f) subsequently at a time T1 injecting the second fluid through the first wellbore into the subterranean formation at an injection rate of R2, wherein the injection rate R2 is less than 50% of the injection rate R1; (g) subsequently injecting the second fluid through the first wellbore into the subterranean formation at an injection rate less than or equal to R2 for a duration of time D1; and (h) subsequently injecting the second fluid through the first wellbore into the subterranean formation at an injection rate of R3, wherein the injection rate R3 is greater than 150% of the injection rate R2.

In an embodiment, the method comprises injecting the second fluid into the first wellbore at a pressure below the minimum horizontal stress in at least a portion of the subterranean formation between steps (d) and (e). In an embodiment, the second fluid is injected into the first wellbore for a duration of time D2 at a pressure below the minimum horizontal stress in at least a portion of the subterranean formation.

In an embodiment, the method comprises (k) injecting the second fluid into the first wellbore at a pressure of less than 90% of the native minimum horizontal stress in at least a portion of the subterranean formation between steps (d) and (e). In an embodiment, at least 10% of the total volume of the second fluid is injected into the first wellbore in step (k).

In an embodiment, the duration of time D2 is greater than 30 minutes, or greater than 2 hours, or greater than 12 hours. In an embodiment, the duration of time D0 is greater than 6 months, or greater than 1 year, or greater than 3 years.

In an embodiment, the second fluid enters the subterranean formation at a pressure greater than or equal to the minimum horizontal stress in at least a portion of the subterranean formation during (e) and (h).

In an embodiment, the injection rate R2 is greater than 5% of the injection rate R1. In an embodiment, the injection rate R3 is in the range of 20 to 200 barrels per minute. In an embodiment, the first or second fluid comprises water, gel, slickwater, hybrid fracturing fluid, viscosified aqueous fluid, acid, foam, carbon dioxide, nitrogen, hydrocarbon, polymer, sand, resin-coated proppant, ceramic proppant, proppant, or any combination thereof

In an embodiment, the method comprises changing the composition of the first or second fluid. In an embodiment, the second fluid does not comprise diverter material during (g). In an embodiment, the duration of time D1 is no less than 10 seconds. In an embodiment, steps (f)-(h) are repeated. In an embodiment, the injection rate R1 is in the range of 20-200 barrels per minute. In an embodiment, the injection rate R2 is greater than or equal to 1 barrel per minute or 5 barrels per minute or 10 barrels per minute.

In an embodiment, the first wellbore has two or more perforated zones. In an embodiment, the ratio of the rate of fluid injected into a first perforated zone over the rate of fluid injected into a second perforated zone is Rr and Rr is less than 1 during step (e), wherein Rr during step (h) is greater than Rr during step (e).

In an embodiment, the method comprises recovering hydrocarbons from the subterranean formation. In an embodiment, the subterranean formation is selected from the group consisting of a low permeability formation, shale formation, tight formation, ultra-tight formation, hydrocarbon-bearing formation, oil reservoir, gas reservoir, hydrocarbon reservoir, and combinations thereof.

In an embodiment, the method comprises placing a second wellbore penetrating the subterranean formation and monitoring the second wellbore to determine time T1. In an embodiment, the fluid pressure in the second wellbore is measured. In an embodiment, at least a portion of the subterranean formation in contact with the second wellbore has been hydraulically fractured. In an embodiment, the fluid pressure in the second wellbore is monitored using a wellhead pressure gauge, a downhole pressure gauge, a downhole retrievable pressure gauge, a downhole fiber optic gauge, or a downhole pressure gauge installed in a bridge plug. In an embodiment, the second wellbore is the first wellbore. In an embodiment, the second fluid does not comprise proppant during (g).

Also discussed herein is a method of producing hydrocarbons from a subterranean formation, the method comprising placing a first wellbore in the subterranean formation; injecting a first fluid through the first wellbore into the subterranean formation at a pressure equal to or greater than the minimum horizontal stress in at least a portion of the formation; creating a hydraulic fracture in the subterranean formation; producing hydrocarbons through the first wellbore for a duration of time D0; injecting a second fluid through the first wellbore into the subterranean formation at an injection rate of R1; at a time T1 injecting the second fluid through the first wellbore into the subterranean formation at an injection rate of R2; injecting the second fluid through the first wellbore into the subterranean formation at an injection rate less than or equal to R2 for a duration of time D1; and injecting the second fluid through the first wellbore into the subterranean formation at an injection rate of R3.

Further discussed herein is a non-transient computer-readable medium including instructions that, when executed by one or more processors, causes the one or more processors to perform a method, the method comprising: (a) placing a first wellbore in the subterranean formation; (b) injecting a first fluid through the first wellbore into the subterranean formation at a pressure equal to or greater than the minimum horizontal stress in at least a portion of the formation; (c) creating a hydraulic fracture in the subterranean formation; (d) producing hydrocarbons through the first wellbore for a duration of time D0; (e) injecting a second fluid through the first wellbore into the subterranean formation at an injection rate of R1; (f) at a time T1 injecting the second fluid through the first wellbore into the subterranean formation at an injection rate of R2, wherein the injection rate R2 is less than 50% of the injection rate R1; (g) injecting the second fluid through the first wellbore into the subterranean formation at an injection rate less than or equal to R2 for a duration of time D1; and (h) injecting the second fluid through the first wellbore into the subterranean formation at an injection rate of R3, wherein the injection rate R3 is greater than 150% of the injection rate R2.

Herein disclosed is a method of completing a first wellbore in a subterranean formation, the method comprising: a) placing a first wellbore in the subterranean formation; b) placing a second wellbore in the subterranean formation; c) injecting a fluid through the first wellbore into the subterranean formation wherein the fluid induces the formation of a stimulation fracture in the subterranean formation; d) measuring a first pressure signal in the second wellbore using a pressure gauge wherein the first pressure signal comprises a poroelastic pressure change induced by the formation of the stimulation fracture; e) subsequently measuring a second pressure signal in the second wellbore using a pressure gauge; 0 determining a first metric in the first pressure signal at a time TT1; g) determining a second metric in the second pressure signal at a time TT2; and h) comparing the first metric with the second metric.

In an embodiment, the first metric is a slope M1 of a pressure verses time curve in the first pressure signal, a pressure P1 of the first pressure signal, or any combination thereof. In an embodiment, the second metric is a slope M2 of a pressure verses time curve in the second pressure signal, a pressure P2 of the second pressure signal, or any combination thereof. In an embodiment, the slope M2 is less than the slope M1 or the pressure P2 is less than the pressure P1. In an embodiment, the fluid distribution entering the subterranean formation at time TT2 is more uniform across the stage than the fluid distribution entering the subterranean formation at time TT1.

In an embodiment, the fluid injection rate into the first wellbore at time TT1 is R1, the fluid injection rate into the first wellbore at time TT2 is R3; and wherein R3 is in the range of 60%-140% of R1. In an embodiment, there is a first change in a first completion design parameter between time TT1 and time TT2 and wherein the first completion design parameter is selected from the group consisting of the fluid injection rate into the first wellbore, the fluid injection pressure in the first wellbore, the volume concentration of proppant in the fluid injected into the first wellbore, the composition of the proppant in the fluid injected into the first wellbore, the number of clusters in a stage in the first wellbore, the number of perforations in a stage in the first wellbore, the completed length of a stage in the first wellbore, the timing of introduction of a material in the fluid injected into the first wellbore, the volume of the fluid injected per stage into the first wellbore, the composition of the fluid injected into the first wellbore, and combinations thereof.

In an embodiment, the fluid injection rate into the first wellbore is R2 after time TT1 but before time TT2 and wherein R2 is no more than 50% of the max of injection rate R1. In an embodiment, the fluid injected through the first wellbore into the subterranean formation at time TT1 and at time TT2 exits the first wellbore at a pressure greater than or equal to the minimum horizontal stress in at least a portion of the subterranean formation.

In an embodiment, the pressure of the fluid exiting the first wellbore into the subterranean formation at time TT2 is no less than 60% of the pressure of the fluid exiting the first wellbore into the subterranean formation at time TT1 and no greater than 140% of the pressure of the fluid exiting the first wellbore into the subterranean formation at time TT1.

In an embodiment, the first metric is not equal to the second metric and a second completion design parameter in the first wellbore is changed. In an embodiment, the second completion design parameter is selected from the group consisting of the fluid injection rate into the first wellbore, the fluid injection pressure in the first wellbore, the volume concentration of proppant in the fluid injected into the first wellbore, the composition of the proppant in the fluid injected into the first wellbore, the number of clusters in a stage in the first wellbore, the number of perforations in a stage in the first wellbore, the completed length of a stage in the first wellbore, the timing of introduction of a material in the fluid injected into the first wellbore, the volume of the fluid injected per stage into the first wellbore, the composition of the fluid injected into the first wellbore, and combinations thereof.

In an embodiment, the second completion design parameter is the fluid injection rate into the first wellbore and wherein at time TT2 the fluid injection rate into the first wellbore is R3 and wherein subsequently the fluid injection rate into the first wellbore is reduced to a rate R4 for a duration of time D2 and wherein subsequently the fluid injection rate into the first wellbore is a rate R5, wherein rate R5 is at least 50% greater than rate R4.

In an embodiment, the duration of time D1 is greater than 1 minute. In an embodiment, no diverter material is introduced into the first wellbore between time TT2 and time TT1. In an embodiment, the heel most stage in the second wellbore is isolated from previous stages toward the toe of the second wellbore by a bridge plug.

In an embodiment, the pressure in the second wellbore is monitored using a wellhead pressure gauge, a downhole pressure gauge, a downhole retrievable pressure gauge, a downhole fiber optic gauge, or a downhole pressure gauge installed in a bridge plug.

In an embodiment, the method comprises forming a monitor fracture in the second wellbore prior to step (c). In an embodiment, the monitor fracture and the stimulation fracture do not intersect. In an embodiment, the fluid comprises water, gel, slickwater, hybrid fracturing fluid, viscosified aqueous fluid, acid, foam, carbon dioxide, nitrogen, hydrocarbon, polymer, sand, resin-coated proppant, ceramic proppant, proppant, or any combination thereof.

In an embodiment, the first wellbore has two or more perforated zones. In an embodiment, at least one perforated zone in the first wellbore is not effectively treated during step (d) and wherein the at least one perforated zone that is not effectively treated during step (d) is effectively treated during step (e). In an embodiment, the ratio of the rate of fluid injected into a first perforated zone to that into a second perforated zone in step (d) is not equal to the ratio of the rate of fluid injected into the first perforated zone to that into the second perforated zone in step (e).

In an embodiment, the method comprises recovering hydrocarbons from the subterranean formation through the first wellbore. In an embodiment, the subterranean formation is selected from the group consisting of a low permeability formation, shale formation, tight formation, ultra-tight formation, hydrocarbon-bearing formation, oil reservoir, gas reservoir, hydrocarbon reservoir, and combinations thereof.

In an embodiment, step (h) is taking place while the fluid is being injected into the first wellbore. In an embodiment, the first wellbore and the second wellbore are the same wellbore.

Further discussed herein is a non-transient computer-readable medium including instructions that, when executed by one or more processors, causes the one or more processors to perform a method, the method comprising: a) placing a first wellbore in the subterranean formation; b) placing a second wellbore in the subterranean formation; c) injecting a fluid through the first wellbore into the subterranean formation wherein the fluid induces the formation of a stimulation fracture in the subterranean formation; d) measuring a first pressure signal in the second wellbore using a pressure gauge wherein the first pressure signal comprises a poroelastic pressure change induced by the formation of the stimulation fracture; e) subsequently measuring a second pressure signal in the second wellbore using a pressure gauge; f) determining a first metric in the first pressure signal at a time TT1; g) determining a second metric in the second pressure signal at a time TT2; and h) comparing the first metric with the second metric.

In an embodiment, the first metric is a slope M1 of a pressure verses time curve in the first pressure signal, a pressure P1 of the first pressure signal, or any combination thereof and the second metric is a slope M2 of a pressure verses time curve in the second pressure signal, a pressure P2 of the second pressure signal, or any combination thereof. In an embodiment, the slope M2 is less than the slope M1 or the pressure P2 is less than the pressure P1. In an embodiment, the fluid distribution entering the subterranean formation at time TT2 is more uniform across the stage than the fluid distribution entering the subterranean formation at time TT1.

In an embodiment, the fluid injection rate into the first wellbore at time TT1 is R1, the fluid injection rate into the first wellbore at time TT2 is R3 and wherein R3 is in the range of 60%-140% of R1. In an embodiment, there is a first change in a first completion design parameter between time TT1 and time TT2 and wherein the completion design parameter is selected from the group consisting of the fluid injection rate into the first wellbore, the fluid injection pressure in the first wellbore, the volume concentration of proppant in the fluid injected into the first wellbore, the composition of the proppant in the fluid injected into the first wellbore, the number of clusters in a stage in the first wellbore, the number of perforations in a stage in the first wellbore, the completed length of a stage in the first wellbore, the timing of introduction of a material in the fluid injected into the first wellbore, the volume of the fluid injected per stage into the first wellbore, the composition of the fluid injected into the first wellbore, and combinations thereof.

In an embodiment, the fluid injection rate into the first wellbore is R2 after time TT1 but before time TT2 and wherein R2 is no more than 50% of the max of injection rate R1. In an embodiment, the fluid injected through the first wellbore into the subterranean formation at time TT1 and at time TT2 exits the first wellbore at a pressure greater than or equal to the minimum horizontal stress in at least a portion of the subterranean formation.

In an embodiment, the pressure of the fluid exiting the first wellbore into the subterranean formation at time TT2 is no less than 60% of the pressure of the fluid exiting the first wellbore into the subterranean formation at time TT1 and no greater than 140% of the pressure of the fluid exiting the first wellbore into the subterranean formation at time TT1.

In an embodiment, the first metric is not equal to the second metric and a second completion design parameter in the first wellbore is changed. In an embodiment, the second completion design parameter is selected from the group consisting of the fluid injection rate into the first wellbore, the fluid injection pressure in the first wellbore, the volume concentration of proppant in the fluid injected into the first wellbore, the composition of the proppant in the fluid injected into the first wellbore, the number of clusters in a stage in the first wellbore, the number of perforations in a stage in the first wellbore, the completed length of a stage in the first wellbore, the timing of introduction of a material in the fluid injected into the first wellbore, the volume of the fluid injected per stage into the first wellbore, the composition of the fluid injected into the first wellbore, and combinations thereof

In an embodiment, the second completion design parameter is the fluid injection rate into the first wellbore and wherein at time TT2 the fluid injection rate into the first wellbore is R3 and wherein subsequently the fluid injection rate into the first wellbore is reduced to a rate R4 for a duration of time D2 and wherein subsequently the fluid injection rate into the first wellbore is a rate R5, wherein rate R5 is at least 50% greater than rate R4.

In an embodiment, the duration of time D1 is greater than 1 minute. In an embodiment, no diverter material is introduced into the first wellbore between time TT2 and time TT1. In an embodiment, the method comprises forming a monitor fracture in the second wellbore prior to step (c). In an embodiment, the monitor fracture and the stimulation fracture do not intersect.

In an embodiment, the first wellbore has at least two perforated zones and wherein at least one perforated zone in the first wellbore is not effectively treated during step (d) and wherein the at least one perforated zone that is not effectively treated during step (d) is effectively treated during step (e). In an embodiment, the first wellbore has at least two perforated zones and wherein the ratio of the rate of fluid injected into a first perforated zone to that into a second perforated zone in step (d) is not equal to the ratio of the rate of fluid injected into the first perforated zone to that into the second perforated zone in step (e).

In an embodiment, the method comprises recovering hydrocarbons from the subterranean formation through the first wellbore. In an embodiment, step (h) is taking place while the fluid is being injected into the first wellbore.

Also disclosed herein is a system for completing a first wellbore in a subsurface formation, comprising: a first wellbore in the subterranean formation; a second wellbore in the subterranean formation; a first fracture configured to be formed in pressure communication with the second wellbore; a second fracture configured to be formed in pressure communication with the first wellbore; a pressure gauge in pressure communication with the fluid in the second wellbore; a computer processor coupled to the pressure gauge, wherein the computer processor is configured to determine a first metric in a first pressure signal from the pressure gauge at time TT1 while the second fracture is being formed and to determine a second metric in a second pressure signal from the pressure gauge at time TT2, wherein the first pressure signal comprises a poroelastic pressure change induced by the formation of the second fracture, and wherein the computer processor is configured to compare the first metric with the second metric. In an embodiment, time TT1 occurs in a first stage and time TT2 occur in a second stage. In an embodiment, the first stage and the second stage are the same stage or different stages.

The foregoing has outlined rather broadly the features and technical advantages of the invention in order that the detailed description of the invention that follows may be better understood. Additional features and advantages of the invention will be described hereinafter that form the subject of the claims of the invention. It should be appreciated by those skilled in the art that the conception and the specific embodiments disclosed may be readily utilized as a basis for modifying or designing other structures for carrying out the same purposes of the invention. It should also be realized by those skilled in the art that such equivalent constructions do not depart from the spirit and scope of the invention as set forth in the appended claims.

BRIEF DESCRIPTION OF THE DRAWINGS

Features and advantages of the methods and apparatus of the embodiments described in this disclosure will be more fully appreciated by reference to the following detailed description of presently preferred but nonetheless illustrative embodiments in accordance with the embodiments described in this disclosure when taken in conjunction with the accompanying drawings in which:

FIG. 1 illustrates a first wellbore and a second wellbore in a subterranean formation (cross-sectional view).

FIG. 2A illustrates fluid distribution across a stage during hydraulic fracturing of a multi-cluster horizontal well using typical completions approaches (cross-sectional view).

FIG. 2B illustrates fracture distribution and reservoir coverage in two adjacent horizontal hydraulically fractured wells using traditional completions approaches (plan view).

FIG. 3A is a simplified process diagram illustrating a method as discussed herein, according to an embodiment of this disclosure.

FIG. 3B injection rate profile during hydraulic fracturing of a multi-cluster stage, according to an embodiment of the method disclosed herein.

FIG. 4A illustates fluid distribution across a stage during hydraulic fracturing of a multi-cluster horizontal well (cross-sectional view), according to an embodiment of this disclosure.

FIG. 4B illustrates fracture distribution and reservoir coverage in two adjacent horizontal hydraulically fractured wells (plan view), according to an embodiment of this disclosure.

FIG. 4C illustrates fracture distribution and reservoir coverage in two adjacent horizontal hydraulically refractured wells using traditional completions approaches (plan view).

FIG. 4D illustrates fracture distribution and reservoir coverage in two adjacent horizontal hydraulically refractured wells (plan view), according to an embodiment of this disclosure.

FIGS. 5A-5C and FIG. 1 illustrate a first wellbore and a second wellbore in a subterranean formation. FIGS. 5A-5C are plan view. FIG. 1 is a cross-sectional view.

FIG. 6 illustrates fracture distribution and reservoir coverage in two adjacent horizontal hydraulically refractured wells using traditional completions approaches (plan view).

FIG. 7 illustrates injection rate profile during hydraulic fracturing of a multi-cluster stage, according to an embodiment of the method disclosed herein.

FIG. 8 illustrates fracture distribution and reservoir coverage in two adjacent horizontal hydraulically refractured wells (plan view), according to an embodiment of this disclosure.

FIGS. 9A-9C illustrate pressure measurement in the second wellbore while forming a fracture in the first wellbore, according to an embodiment of this disclosure.

While embodiments described in this disclosure may be susceptible to various modifications and alternative forms, specific embodiments thereof are shown by way of example in the drawings and will herein be described in detail. It should be understood, however, that the drawings and detailed description thereto are not intended to limit the embodiments to the particular form disclosed, but on the contrary, the intention is to cover all modifications, equivalents and alternatives falling within the spirit and scope of the appended claims. The headings used herein are for organizational purposes only and are not meant to be used to limit the scope of the description. As used throughout this application, the word “may” is used in a permissive sense (i.e., meaning having the potential to), rather than the mandatory sense (i.e., meaning must). Similarly, the words “include”, “including”, and “includes” mean including, but not limited to.

Various units, circuits, or other components may be described as “configured to” perform a task or tasks. In such contexts, “configured to” is a broad recitation of structure generally meaning “having circuitry that” performs the task or tasks during operation. As such, the unit/circuit/component can be configured to perform the task even when the unit/circuit/component is not currently on. In general, the circuitry that forms the structure corresponding to “configured to” may include hardware circuits and/or memory storing program instructions executable to implement the operation. The memory can include volatile memory such as static or dynamic random access memory and/or nonvolatile memory such as optical or magnetic disk storage, flash memory, programmable read-only memories, etc. The hardware circuits may include any combination of combinatorial logic circuitry, clocked storage devices such as flops, registers, latches, etc., finite state machines, memory such as static random access memory or embedded dynamic random access memory, custom designed circuitry, programmable logic arrays, etc. Similarly, various units/circuits/components may be described as performing a task or tasks, for convenience in the description. Such descriptions should be interpreted as including the phrase “configured to.” Reciting a unit/circuit/component that is configured to perform one or more tasks is expressly intended not to invoke 35 U.S.C. § 112(f) interpretation for that unit/circuit/component.

The scope of the present disclosure includes any feature or combination of features disclosed herein (either explicitly or implicitly), or any generalization thereof, whether or not it mitigates any or all of the problems addressed herein. Accordingly, new claims may be formulated during prosecution of this application (or an application claiming priority thereto) to any such combination of features. In particular, with reference to the appended claims, features from dependent claims may be combined with those of the independent claims and features from respective independent claims may be combined in any appropriate manner and not merely in the specific combinations enumerated in the appended claims.

DETAILED DESCRIPTION

In this disclosure, the features as discussed herein are combinable unless otherwise specified. All such combinations are within the scope of this disclosure. Unless particularly specified, the elements or steps in a process do not have implications regarding sequence or order of said elements or steps, meaning that all combinations of sequences are contemplated to be within the scope of the disclosure.

Referring to FIG. 1, an illustration of a first wellbore and a second wellbore in a subterranean formation (cross-sectional view) is shown. In FIG. 1, 172 represents the subterranean formation; 164 represents the first wellbore; 162 represents the second wellbore; 166 represents hydraulic fractures; 168 represents the heel side of wellbores; 170 represents toe side of wellbores; 174 represents formation of a new stimulation fracture in the first wellbore during hydraulic fracturing; and 180 represents surface wellhead pressure gauge attached to the wellhead of the second wellbore.

Referring to FIG. 2A, an illustration of fluid distribution across a stage during hydraulic fracturing of a multi-cluster horizontal well using typical completions approaches (cross-sectional view) is shown. In FIG. 2A, 202 represents heal of stage; 204 represents toe of stage; 206 represents perforation cluster 1; 208 represents perforation cluster 2; 210 represents perforation cluster 3; 212 represents perforation cluster 4; and 214 represents volume of fluid injected into the formation per lateral foot along the well.

Referring to FIG. 2B, an illustration of fracture distribution and reservoir coverage in two adjacent horizontal hydraulically fractured wells using traditional completions approaches (plan view) is presented. In FIG. 2B, 220 representes a first stimulated well; 240 representes a second stimulated well; and 260 represents hydraulic fracture distribution.

Referring to FIG. 3A, a simplified process diagram illustrating an embodiment of the method as discussed herein is presented. In FIG. 3A, 301 represents (a) placing a first wellbore in a subterranean formation; 302 represents (b) injecting fluid through the first wellbore at an injection rate of R1; 303 represents (c) at time T1, injecting fluid through the first wellbore at an injection rate of R2; 304 represents (d) injecting fluid through the first wellbore at an injection rate less than or equal to R2 for a duration of time D1; 305 represents (e) injecting fluid through the first wellbore at an injection rate of R3; 306 represents the optional step of repeating (c)-(e); and 307 represents producing hydrocarbons/oil from the subterranean formation.

Referring to FIG. 3B, an illustration of injection rate profile during hydraulic fracturing of a multi-cluster stage is presented, according to an embodiment of the method disclosed herein. In FIG. 3B, 322 represents injection rate R1; 324 represents injection rate R2; 326 represents injection rate R3; 318 represent Period 1; 328 represents time T1; 330 represent duration D1; and 320 represents Period 2.

Referring to FIG. 4A, an illustration of fluid distribution across a stage during hydraulic fracturing of a multi-cluster horizontal well (cross-sectional view) is presented, according to an embodiment of this disclosure. In FIG. 4A, 402 represents heal of stage; 404 represents toe of stage; 406 represents perforation cluster 1; 408 represents perforation cluster 2; 410 represents perforation cluster 3; 412 represents perforation cluster 4; 414 represents volume of fluid injected into the formation per lateral foot along the well in Period 1; and 416 represents volume of fluid injected into the formation per lateral foot along the well in Period 2. With the use of the methods and systems as disclosed herein, the fluid distribution across a stage is significantly improved.

Referring to FIG. 4B, an illustration of fracture distribution and reservoir coverage in two adjacent horizontal hydraulically fractured wells (plan view) is presented, according to an embodiment of this disclosure. In FIG. 4B, 420 represents a first stimulated well; 440 represents a second stimulated well; and 460 represents hydraulic fracture distribution. With the use of the methods and systems as disclosed herein, the hydraulic fracture distribution and reservoir coverage are significantly improved.

In an embodiment, a method of injecting a fluid into a subterranean formation is discussed. The method comprises: placing a first wellbore in the subterranean formation; injecting the fluid through the first wellbore into the subterranean formation at an injection rate of R1, wherein R1 is varied with time or fixed; injecting the fluid through the first wellbore into the subterranean formation at an injection rate of R2 for a duration of time D1, wherein R2 is varied with time or fixed and R2 is in the range of 5%-50% of the max of injection rate R1; injecting the fluid through the first wellbore into the subterranean formation at an injection rate of R3, wherein the injection rate R3 is varied with time or fixed and the max of injection rate R3 is greater than 150% of the minimum of injection rate R2. When the fluid is injected into the subterranean formation at injection rate of R1 or R3, the fluid enters at a pressure greater than or equal to the minimum horizontal stress in at least a portion of the subterranean formation. At such pressure(s), the subterranean formation is fractured.

In an embodiment, a method of injecting a fluid into a subterranean formation comprises: (a) placing a first wellbore in the subterranean formation; (b) injecting the fluid through the first wellbore into the subterranean formation at an injection rate of R1, wherein the fluid enters the subterranean formation at a pressure greater than or equal to the minimum horizontal stress in at least a portion of the subterranean formation; (c) subsequently at a time T1 injecting the fluid through the first wellbore into the subterranean formation at an injection rate of R2, wherein the injection rate R2 is less than 50% of the injection rate R1 and greater than 5% of the injection rate R1; (d) subsequently injecting the fluid through the first wellbore into the subterranean formation at an injection rate less than or equal to R2 for a duration of time D1; (e) subsequently injecting the fluid through the first wellbore into the subterranean formation at an injection rate of R3, wherein the fluid enters the subterranean formation at a pressure greater than or equal to the minimum horizontal stress in at least a portion of the subterranean formation, wherein the injection rate R3 is greater than 150% of the injection rate R2.

In this disclosure, the injected fluid comprises water, gel, slickwater, hybrid fracturing fluid, viscosified aqueous fluid, acid, foam, carbon dioxide, nitrogen, hydrocarbon, polymer, sand, resin-coated proppant, ceramic proppant, proppant, or any combination thereof. In various embodiments, the method comprises changing the composition of the fluid. In some cases, the fluid does not comprise diverter material during step (d). In some cases, the fluid does not comprise diverter material. In some cases, the fluid does not comprise diverter material during duration of time D1. In some cases, the second fluid does not comprise more than 100 pounds per gallon of diverter material. In some cases, the second fluid does not comprise more than 10 pounds per gallon of diverter material. In some cases, the second fluid does not comprise more than 1 pound per gallon of diverter material.

In this disclosure, the duration of time D1 is no less than 30 seconds. In some embodiments, the duration of time D1 is no less than 5 minutes, no less than 10 minutes, or no less than 30 minutes. In some embodiments, the duration of time D1 is less than 3 hours. In some embodiments, the duration of time D1 is less than 2 hours. In some embodiments, the duration of time D1 is from 1 minute to 30 minutes. In some embodiments, the duration of time D1 is from 5 minutes to 15 minutes.

In an embodiment, steps (c)-(e) are repeated. Such repetition is once or multiple times. In various embodiments, the injection rate R1 is greater than or equal to 20 barrels per minute, greater than 50 barrels per minute, or greater than 100 barrels per minute. In various embodiments, the injection rate R2 is greater than or equal to 1 barrel per minute, greater than or equal to 5 barrels per minute, greater than or equal to 10 barrels per minute, or greater than or equal to 20 barrels per minute.

In this disclosure, the first wellbore has two or more perforated zones. In various embodiments, wherein at least one perforated zone is not effectively treated during step (b) but is effectively treated during step (e). Not effectively treated is typically understood as a disproportionately small amount of fluid is passing through a perforated zone. In various embodiments, wherein the ratio of fluid entering the perforated zones in step (b) is different than the ratio of fluid entering the perforated zones in step (e). Step (e) causes an improvement of the fluid ratio compared to what is achieved in step (b). In this disclosure, the ratio of the rate of fluid injected into a first perforated zone over the rate of fluid injected into a second perforated zone is Rr and Rr is less than 1 during step (b), wherein Rr during step (e) is greater than Rr during step (b), meaning that the ratio Rr has improved in step (e) over step (b). For example, during step (b) the rate of fluid injected into a first perforated zone is 10% of the rate of fluid injected into a second perforated zone and during step (e) the rate of fluid injected into the first perforated zone is 20% of the rate of fluid injected into the second perforated zone. For example, during step (b) the rate of fluid injected into a first perforated zone is in the range of from 10%-75% of the rate of fluid injected into a second perforated zone and during step (e) the rate of fluid injected into the first perforated zone is in the range of 20%-200% of the rate of fluid injected into the second perforated zone.

In various embodiments, the method further comprises recovering hydrocarbons from the subterranean formation through the first wellbore. In various embodiments, the recovery of hydrocarbons using the instant methods and systems is uplifted by 10% or more. In various embodiments, the recovery of hydrocarbons using the instant methods and systems is uplifted by 20% or more. In various embodiments, the recovery of hydrocarbons using the instant methods and systems is uplifted by 30% or more. In various embodiments, the recovery of hydrocarbons using the instant methods and systems is uplifted by 40% or more. In various embodiments, the recovery of hydrocarbons using the instant methods and systems is uplifted by 50% or more. In various embodiments, the recovery of hydrocarbons using the instant methods and systems is uplifted by 60% or more. In various embodiments, the recovery of hydrocarbons using the instant methods and systems is uplifted by 70% or more. In various embodiments, the recovery of hydrocarbons using the instant methods and systems is uplifted by 80% or more. In various embodiments, the recovery of hydrocarbons using the instant methods and systems is uplifted by 90% or more. In various embodiments, the recovery of hydrocarbons using the instant methods and systems is uplifted by 100% or more.

In some embodiments, the subterranean formation is a low permeability formation, shale formation, tight formation, ultra-tight formation, hydrocarbon-bearing formation, oil reservoir, gas reservoir, hydrocarbon reservoir, or any combination thereof. In various embodiments, the subterranean formation is hydraulically fractured.

In various embodiments, the method comprises placing a second wellbore penetrating the subterranean formation and monitoring the second wellbore to determine time T1. In various embodiments, the fluid pressure in the second wellbore is measured. In various embodiments, the fluid pressure in the second wellbore is measured using a wellhead pressure gauge, a downhole pressure gauge, a downhole retrievable pressure gauge, a downhole fiber optic gauge, or a downhole pressure gauge installed in a bridge plug. In some embodiments, the fluid pressure changes in the second wellbore. In some embodiments the change in fluid pressure in the second wellbore results from a poroelastic response. In some embodiments, the change in fluid pressure in the second wellbore results from a poroelastic response as a result of the formation of a fracture due to injection of fluid into the first wellbore. In various embodiments, at least a portion of the subterranean formation in contact with the second wellbore has been hydraulically fractured. In an embodiment, the first wellbore and the second wellbore are the same wellbore. For instance, this can occur when pressure is monitored in a previously completed stage that is isolated from another stage being completed in the same well, such as the case in a sliding sleeve completion with coiled tubing or in a scenario where a downhole pressure gauge or fiber line reading pressure in a previously completed stage (that is isolated from the stage being completed by a bridge plug) can be monitored real time.

A poroelastic response is one induced by displacement of a solid. For instance, when a stimulated fracture is forming it applies a pressure to the rock matrix or formation. If this pressure is different from the natural reservoir pressure in the formation, then it will cause a strain or displacement of the formation. This applied pressure from the stimulated fracture also results in a change in the Dirichlet stress boundary condition. These changes result in changes in the stress field in the formation. A change in the stress field in the formation near an observation fracture will result in a change in the fluid pressure in the observation fracture. This phenomenon is distinctly different from a change in fluid pressure due to direct fluid communication. Direct fluid communication can occur when fluids are in direct physical contact as in where the observation fracture and the stimulated fracture intersect. Direct fluid communication can also occur when the observation fracture and stimulated fracture are both in contact with a high permeability pathway, such as the fluid in a wellbore.

In some embodiments, time T1 is determined prior to treating the stage. In some embodiments, time T1 is approximately determined and approximately a fixed duration after starting injection treatment of the stage. In some embodiments, time T1 occurs after a pre-determined volume of fluid is injected into the well. In some embodiments, time T1 is determined by monitoring fluid distribution, fracture growth rates, pressure responses or other phenomenon in the first well being stimulated or in a second well in the subterranean formation. In various embodiments, such monitoring is performed using microseismic, fiber optics, well head pressure monitoring, downhole pressure monitoring, fluid injection rate, surface or downhole tilt meters, or any combination thereof. In some embodiments, such monitoring is done from a second well adjacent to the first well where the injection is occurring.

In some embodiments, at least a portion of the subterranean formation in proximity to the second well has been hydraulically fractured prior to stimulating the first well. In some embodiments, the second well is at least partially filled with water, slickwater, gel, hybrid frac fluid, energized fluid, fracturing fluid, gas, hydrocarbon, or another fluid. In some embodiments, the second well is recently completed, or in the process of being completed, or completed and has produced for a period of time, or not yet completed. In some embodiments, the second well has one or more perforated zones. In various embodiments, at least a portion of the second well is within 100 feet, 500 feet, 1,000 feet, or 2,500 feet of at least a portion of the first well. In various embodiments, at least a portion of the second wellbore is vertical, horizontal, or slanted within the formation.

In some embodiments, the duration of time D1 is determined before the injection treatment. In some embodiments, the duration of time D1 is approximately constant. In some embodiments, the duration of time D1 varies. In some embodiments, the duration of time D1 is determined based on monitoring in the first well, in the second well, or any combination thereof.

During the period of injection at rate less than or equal to R2, in some embodiments, no diverter material is injected into the first well. This is contrary to the process of diverter injection, wherein a diverter material is introduced into the wellbore. In various embodiments, the controlled injection process as described herein is able to divert the fluid automatically to clusters which previously were not effectively treated without injection of diverting agents.

In some embodiments, the subterranean formation is a hydrocarbon bearing formation. In some embodiments, the subterranean formation is an oil bearing formation, a water bearing formation, a hydrocarbon gas bearing formation, or a carbon dioxide (CO₂) bearing formation. In some embodiments, the subterranean formation is a shale, a tight formation, an ultra-tight formation, a carbonate, or an unconventional play. The well test permeability of the subterranean formation, in some cases, is less than 10 Darcy, less than 1 Darcy, less than 1 milli-Darcy, less than 100 micro-Darcy, less than 1 micro-Darcy, or less than 10 nano-Darcy.

In some embodiments, the methods and systems as discussed herein are used for hydraulic fracturing. In some embodiments, the methods and systems as discussed herein are used for matrix treatments.

In some embodiments, the wellbore penetrating the subterranean formation is cased, cemented, open hole with external packers, perforated, slotted, or jetted. In embodiments, the wellbore is vertical, approximately horizontal, or slanted in at least a portion of the subterranean formation.

In some embodiments, the fluid comprises water, gel, slickwater, hybrid fracturing fluid, viscosified aqueous fluid, acid, foam, carbon dioxide, nitrogen, hydrocarbon, polymer, sand, resin-coated proppant, ceramic proppant, proppant, or any combination thereof. In some embodiments, the fluid composition changes with time. In some embodiments, the fluid does not contain proppant. In some embodiments, the fluid contains proppant only during certain times in the injection process.

In some embodiments, the fluid comprises proppant and the concentration of proppant changes with time. In some embodiments, the fluid also contains other additives, for example, acids, pH control agents, biocides, corrosion inhibitors, crosslinkers, breakers, anti-oxidants, buffers, viscosifiers, polymers, biopolymers, guar gum, high-molecular weight polysaccharides, hydroxy-ethyl-cellulose, poly-saccharides, polyacrylamide, copolymers, crosslink polymers, xanthan gum, alcohol, surfactants, viscoelastic surfactants, cationic surfactants, anionic surfactants, zwitterionic surfactants, amphoteric surfactants, and/or fluid loss additives.

In some embodiments, the fluid is an energized fluid or foam comprising carbon dioxide, nitrogen, air, hydrocarbons or any combination thereof. In some embodiments, the fluid further comprises surfactants. In some embodiments, the fluid comprises proppant such as sand, ceramic proppant, resin-coated proppant, pre-cured resin coated, or bauxite. In some embodiments, the concentration of the proppant in the fluid is in the range of from 0 kg/L to 1 kg/L. In some embodiments, the concentration of the proppant in the fluid is greater than 1 kg/L.

In some embodiments, proppant is injected into the formation at 0 pounds per foot (lateral foot along the wellbore), at greater than 500 pounds per foot, at greater than 5,000 pounds per foot. In some embodiments, proppant is injected into the formation at less than 500 pounds per foot, or less than 5,000 pounds. Proppant is generally understood by one skilled in the art, for example, it is a material with an average particle size ranging from about 100 micro-meters to about 1 cm. Proppant sizes, in some embodiments, are 100 mesh, 30/50 mesh, 40/60 mesh, 20/40 mesh, 8/20 mesh.

In some embodiments, the fluid comprises a breaker such as metal chelators, enzymes, oxidative breakers, pH modifiers, polymers or other micelle destabilizing chemicals or materials.

Also disclosed herein is a non-transient computer-readable medium including instructions that, when executed by one or more processors, causes the one or more processors to perform a method, the method comprising: placing a first wellbore in the subterranean formation; injecting the fluid through the first wellbore into the subterranean formation at an injection rate of R1, wherein R1 is varied with time or fixed, subsequently injecting the fluid through the first wellbore into the subterranean formation at an injection rate of R2 for a duration of time D1, wherein R2 is varied with time or fixed and R2 is in the range of 5%-50% of the max of injection rate R1; subsequently injecting the fluid through the first wellbore into the subterranean formation at an injection rate of R3, wherein R3 is varied with time or fixed and wherein the max of injection rate R3 is greater than 150% of the minimum of injection rate R2.

In an embodiment, a non-transient computer-readable medium contains instructions that, when executed by one or more processors, causes the one or more processors to perform a method, the method comprising: placing a first wellbore in the subterranean formation; injecting the fluid through the first wellbore into the subterranean formation at an injection rate of R1, wherein R1 is varied with time or fixed; injecting the fluid through the first wellbore into the subterranean formation at an injection rate of R2 for a duration of time D1, wherein R2 is varied with time or fixed and R2 is in the range of 5%-50% of the max of injection rate R1; injecting the fluid through the first wellbore into the subterranean formation at an injection rate of R3, wherein R3 is varied with time or fixed and wherein the max of injection rate R3 is greater than 150% of the minimum of injection rate R2. The method executed by said one or more processors instructed by the non-transient computer-readable medium includes all the features and combinations of the methods as discussed herein.

Advantages. There are numerous advantages of the method described herein. First, operationally this method is easy to execute in the field real-time as injection rate is the most easily controlled parameter during hydraulic fracturing treatments or fluid injection treatments into a wellbore. Second, the method is low cost as no new material needs to be introduced into the wellbore to achieve diversion. Furthermore, third, the approach is more reliable at improving fluid distribution than alternatives. For instance, it has a higher propensity to improve fluid distribution along the lateral more consistently than introducing a diverter material, which can actually worsen fluid distribution along the lateral by blocking of perforations taking less fluid and increasing fluid injection into perforations that are already taking a disproportionally large amount of fluid. Fourth, the improvements in oil production seen with the method discussed herein exceed those observed with other techniques targeted at improving fluid distribution along the wellbore. Fifth, the method described herein can be used with a broad range of completions designs. Sixth, the method described herein can be better controlled and tailored to achieve the desired result than alternative methods targeted at improving fluid distribution. For instance, alternative technologies, such as introducing diverter material into the well, can be difficult to control. Sometimes introduction of diverter material results in a screen-out and an inability to finish pumping the target volume of fluid into a well. The method described herein does not increase the potential for a screen-out and is more controllable and lower risk than alternative methods.

In this disclosure, the features as discussed herein are combinable unless otherwise specified. All such combinations are within the scope of this disclosure. Unless particularly specified, the elements or steps in a process do not have implications regarding sequence or order of said elements or steps, meaning that all combinations of sequences are contemplated to be within the scope of this disclosure.

Referring to FIG. 4C, an illustration of fracture distribution and reservoir coverage in two adjacent horizontal hydraulically fractured and refractured wells using traditional completions approaches (plan view) is presented. In FIG. 4C, 220 representes a first stimulated well; 240 representes a second stimulated well; 260 represents hydraulic fracture distribution after the initial hydraulic fracturing job; and 280 represents the new hydraulic fractures formed after refracturing.

Referring to FIG. 4D, an illustration of fracture distribution and reservoir coverage in two adjacent horizontal hydraulically fractured and refractured wells (plan view) is presented, according to an embodiment of this disclosure. In FIG. 4D, 420 represents a first stimulated well; 440 represents a second stimulated well; 460 represents hydraulic fracture distribution after the initial hydraulic fracturing job; and 480 represents the new hydraulic fractures formed after refracturing. With the use of the methods and systems as disclosed herein, the hydraulic fracture distribution and reservoir coverage are significantly improved.

Herein disclosed is a method of producing hydrocarbons from a subterranean formation. The method comprises placing a first wellbore in the subterranean formation; injecting a first fluid through the first wellbore into the subterranean formation at a pressure equal to or greater than the minimum horizontal stress in at least a portion of the formation so that the subterranean formation is fractured; creating a hydraulic fracture in the subterranean formation; producing hydrocarbons through the first wellbore for a duration of time D0; injecting a second fluid through the first wellbore into the subterranean formation at an injection rate of R1; at a time T1 injecting the second fluid through the first wellbore into the subterranean formation at an injection rate of R2; injecting the second fluid through the first wellbore into the subterranean formation at an injection rate less than or equal to R2 for a duration of time D1; and injecting the second fluid through the first wellbore into the subterranean formation at an injection rate of R3.

Herein disclosed is a method of producing hydrocarbons from a subterranean formation. The method comprises (a) placing a first wellbore in the subterranean formation; (b) injecting a first fluid through the first wellbore into the subterranean formation at a pressure equal to or greater than the minimum horizontal stress in at least a portion of the formation; (c) creating a hydraulic fracture in the subterranean formation; (d) subsequently producing hydrocarbons through the first wellbore for a duration of time D0; (e) subsequently injecting a second fluid through the first wellbore into the subterranean formation at an injection rate of R1; (f) subsequently at a time T1 injecting the second fluid through the first wellbore into the subterranean formation at an injection rate of R2, wherein the injection rate R2 is less than 50% of the injection rate R1; (g) subsequently injecting the second fluid through the first wellbore into the subterranean formation at an injection rate less than or equal to R2 for a duration of time D1; and (h) subsequently injecting the second fluid through the first wellbore into the subterranean formation at an injection rate of R3, wherein the injection rate R3 is greater than 150% of the injection rate R2.

Herein disclosed is a method of producing hydrocarbons from a subterranean formation. The method comprises (a) placing a first wellbore in the subterranean formation; (b) injecting a first fluid through the first wellbore into the subterranean formation at a pressure equal to or greater than the minimum horizontal stress in at least a portion of the formation; (c) creating a hydraulic fracture in the subterranean formation; (d) subsequently producing hydrocarbons through the first wellbore for a duration of time D0; (e) subsequently injecting a second fluid through the first wellbore into the subterranean formation at an injection rate of R1 wherein R1 is varied with time or fixed; (f) subsequently at a time T1 injecting the second fluid through the first wellbore into the subterranean formation at an injection rate of R2, wherein the injection rate R2 is varied with time or fixed and wherein the injection rate R2 is less than 50% of the max of the injection rate R1; (g) subsequently injecting the second fluid through the first wellbore into the subterranean formation at an injection rate of R2 for a duration of time D1; and (h) subsequently injecting the second fluid through the first wellbore into the subterranean formation at an injection rate of R3, wherein the injection rate R3 is varied with time or fixed and wherein the max of injection rate R3 is greater than 150% of the minimum of injection rate R2.

In an embodiment, the method comprises injecting the second fluid into the first wellbore at a pressure below the minimum horizontal stress in at least a portion of the subterranean formation between steps (d) and (e). In an embodiment, the second fluid is injected into the first wellbore for a duration of time D2 at a pressure below the minimum horizontal stress in at least a portion of the subterranean formation.

In an embodiment, the method comprises (k) injecting the second fluid into the first wellbore at a pressure of less than 90% of the native minimum horizontal stress in at least a portion of the subterranean formation between steps (d) and (e) where a native minimum horizontal stress is a minimum horizontal stress found in a formation prior to any anthropogenic activity. In an embodiment, at least 10% of the total volume of the second fluid is injected into the first wellbore in step (k). In an embodiment the method comprises (k) injecting the second fluid into the first wellbore at a pressure of less than 90% of the current minimum horizontal stress in at least a portion of the subterranean formation between steps (d) and (e) where a current minimum horizontal stress is a minimum horizontal stress found in a formation at the current time.

In an embodiment, the duration of time D2 is greater than 30 minutes, or greater than 2 hours, or greater than 12 hours. In an embodiment, the duration of time D0 is greater than 6 months, or greater than 1 year, or greater than 3 years.

In an embodiment, the second fluid enters the subterranean formation at a pressure greater than or equal to the minimum horizontal stress in at least a portion of the subterranean formation during (e) and (h).

In an embodiment, the first or second fluid comprises water, gel, slickwater, hybrid fracturing fluid, viscosified aqueous fluid, acid, foam, carbon dioxide, nitrogen, hydrocarbon, polymer, sand, resin-coated proppant, ceramic proppant, proppant, or any combination thereof. In various embodiments, the method comprises changing the composition of the first or second fluid. In some cases, the first or second fluid does not comprise diverter material during step (g). In some cases, the first or second fluid does not comprise diverter material. In some cases, the first or second fluid does not comprise diverter material during duration of time D1. In some cases, the second fluid does not comprise more than 100 pounds per gallon of diverter material. In some cases, the second fluid does not comprise more than 10 pounds per gallon of diverter material. In some cases, the second fluid does not comprise more than 1 pound per gallon of diverter material. In an embodiment, the second fluid does not comprise proppant during (g).

In an embodiment, the duration of time D1 is no less than 10 seconds. In an embodiment, the duration of time D1 is from 1 minute to 30 minutes. In an embodiment, the duration of time D1 is from 5 minutes to 15 minutes. In an embodiment, the duration of time D1 is no less than 1 hour. In an embodiment, the duration of time D1 is no less than 2 hours. In an embodiment, the duration of time D1 is no less than 3 hours. In an embodiment, the duration of time D1 is less than 2 weeks.

In an embodiment, steps (f)-(h) are repeated. In an embodiment, the injection rate R1 is in the range of 20-200 barrels per minute. In an embodiment, the injection rate R2 is greater than 5% of the injection rate R1. In an embodiment, the injection rate R2 is greater than or equal to 1 barrel per minute, or 5 barrels per minute, or 10 barrels per minute. In an embodiment, the injection rate R2 is 0 barrels per minute. In an embodiment, the injection rate R3 is in the range of 20 to 200 barrels per minute.

In an embodiment, the first wellbore has two or more perforated zones. In various embodiments, wherein at least one perforated zone is not effectively treated during step (e) but is effectively treated during step (h). Not effectively treated is typically understood as a disproportionately small amount of fluid is passing through a perforated zone. In various embodiments, wherein the ratio of fluid entering the perforated zones in step (e) is different than the ratio of fluid entering the perforated zones in step (h). Step (h) causes an improvement of the fluid ratio compared to what is achieved in step (e). In this disclosure, the ratio of the rate of fluid injected into a first perforated zone over the rate of fluid injected into a second perforated zone is Rr and Rr is less than 1 during step (e), wherein Rr during step (h) is greater than Rr during step (e), meaning that the ratio Rr has improved in step (h) over step (e). For example, during step (e) the rate of fluid injected into a first perforated zone is 10% of the rate of fluid injected into a second perforated zone and during step (h) the rate of fluid injected into the first perforated zone is 20% of the rate of fluid injected into the second perforated zone. For example, during step (e) the rate of fluid injected into a first perforated zone is in the range of from 10%-75% of the rate of fluid injected into a second perforated zone and during step (h) the rate of fluid injected into the first perforated zone is in the range of 20%-200% of the rate of fluid injected into the second perforated zone.

In an embodiment, the method comprises recovering hydrocarbons from the subterranean formation. In an embodiment, the method comprises recovering hydrocarbons from the subterranean formation through the first wellbore. In various embodiments, the recovery of hydrocarbons using the instant methods and systems is uplifted by 10% or more. In various embodiments, the recovery of hydrocarbons using the instant methods and systems is uplifted by 20% or more. In various embodiments, the recovery of hydrocarbons using the instant methods and systems is uplifted by 30% or more. In various embodiments, the recovery of hydrocarbons using the instant methods and systems is uplifted by 40% or more. In various embodiments, the recovery of hydrocarbons using the instant methods and systems is uplifted by 50% or more. In various embodiments, the recovery of hydrocarbons using the instant methods and systems is uplifted by 60% or more. In various embodiments, the recovery of hydrocarbons using the instant methods and systems is uplifted by 70% or more. In various embodiments, the recovery of hydrocarbons using the instant methods and systems is uplifted by 80% or more. In various embodiments, the recovery of hydrocarbons using the instant methods and systems is uplifted by 90% or more. In various embodiments, the recovery of hydrocarbons using the instant methods and systems is uplifted by 100% or more.

In an embodiment, the subterranean formation is a low permeability formation, shale formation, tight formation, ultra-tight formation, hydrocarbon-bearing formation, oil reservoir, gas reservoir, hydrocarbon reservoir, or any combination thereof. In various embodiments, the subterranean formation is hydraulically fractured.

In an embodiment, the method comprises placing a second wellbore penetrating the subterranean formation. In an embodiment, the method comprises monitoring the second wellbore to determine time T1. In various embodiments, the fluid pressure in the second wellbore is measured. In an embodiment, at least a portion of the subterranean formation in contact with the second wellbore has been hydraulically fractured. In various embodiments, the fluid pressure in the second wellbore is measured using a wellhead pressure gauge, a downhole pressure gauge, a downhole retrievable pressure gauge, a downhole fiber optic gauge, or a downhole pressure gauge installed in a bridge plug. In some embodiments, the fluid pressure changes in the second wellbore. In some embodiments the change in fluid pressure in the second wellbore results from a poroelastic response. In some embodiments, the change in fluid pressure in the second wellbore results from a poroelastic response as a result of the formation of a fracture due to injection of fluid into the first wellbore. In various embodiments, at least a portion of the subterranean formation in contact with the second wellbore has been hydraulically fractured. In an embodiment, the first wellbore and the second wellbore are the same wellbore. For instance, this can occur when pressure is monitored in a previously completed stage that is isolated from another stage being completed in the same well, such as the case in a sliding sleeve completion with coiled tubing or in a scenario where a downhole pressure gauge or fiber line reading pressure in a previously completed stage (that is isolated from the stage being completed by a bridge plug) can be monitored real time.

A poroelastic response is one induced by displacement of a solid. For instance, when a stimulated fracture is forming it applies a pressure to the rock matrix or formation. If this pressure is different from the natural reservoir pressure in the formation, then it will cause a strain or displacement of the formation. This applied pressure from the stimulated fracture also results in a change in the Dirichlet stress boundary condition. These changes result in changes in the stress field in the formation. A change in the stress field in the formation near an observation fracture will result in a change in the fluid pressure in the observation fracture. This phenomenon is distinctly different from a change in fluid pressure due to direct fluid communication. Direct fluid communication can occur when fluids are in direct physical contact as in where the observation fracture and the stimulated fracture intersect. Direct fluid communication can also occur when the observation fracture and stimulated fracture are both in contact with a high permeability pathway, such as the fluid in a wellbore.

In some embodiments, time T1 is determined prior to treating the stage. In some embodiments, time T1 is approximately determined and approximately a fixed duration after starting injection treatment of the stage. In some embodiments, time T1 occurs after a pre-determined volume of fluid is injected into the well. In some embodiments, time T1 is determined by monitoring fluid distribution, fracture growth rates, pressure responses or other phenomenon in the first well being stimulated or in a second well in the subterranean formation. In various embodiments, such monitoring is performed using microseismic, fiber optics, well head pressure monitoring, downhole pressure monitoring, fluid injection rate, surface or downhole tilt meters, or any combination thereof In some embodiments, such monitoring is done from a second well adjacent to the first well where the injection is occurring.

In some embodiments, at least a portion of the subterranean formation in proximity to the second well has been hydraulically fractured prior to stimulating the first well. In some embodiments, the second well is at least partially filled with water, slickwater, gel, hybrid frac fluid, energized fluid, fracturing fluid, gas, hydrocarbon, or another fluid. In some embodiments, the second well is recently completed, or in the process of being completed, or completed and has produced for a period of time, or not yet completed. In some embodiments, the second well has one or more perforated zones. In various embodiments, at least a portion of the second well is within 100 feet, 500 feet, 1,000 feet, or 2,500 feet of at least a portion of the first well. In various embodiments, at least a portion of the second wellbore is vertical, horizontal, or slanted within the formation.

In some embodiments, the duration of time D1 is determined before the injection treatment. In some embodiments, the duration of time D1 is approximately constant from cycle to cycle(or from injection stage to injection stage). In some embodiments, the duration of time D1 varies from cycle to cycle (or from injection stage to injection stage). In some embodiments, the duration of time D1 is determined based on monitoring in the first well, in the second well, or any combination thereof

During the period of injection at rate less than or equal to R2, in some embodiments, no diverter material is injected into the first well. This is contrary to the process of diverter injection, wherein a diverter material is introduced into the wellbore. In various embodiments, the controlled injection process as described herein is able to divert the fluid automatically to clusters which previously were not effectively treated without injection of diverting agents.

In some embodiments, the subterranean formation is a hydrocarbon bearing formation. In some embodiments, the subterranean formation is an oil bearing formation, a water bearing formation, a hydrocarbon gas bearing formation, or a carbon dioxide (CO₂) bearing formation. In some embodiments, the subterranean formation is a shale, a tight formation, an ultra-tight formation, a carbonate, or an unconventional play. The well test permeability of the subterranean formation, in some cases, is less than 10 Darcy, less than 1 Darcy, less than 1 mili-Darcy, less than 100 micro-Darcy, less than 1 micro-Darcy, or less than 10 nano-Darcy.

In some embodiments, the methods and systems as discussed herein are used for hydraulic fracturing. In some embodiments, the methods and systems as discussed herein are used for matrix treatments.

In some embodiments, the wellbore penetrating the subterranean formation is cased, cemented, open hole with external packers, perforated, slotted, or jetted. In embodiments, the wellbore is vertical, approximately horizontal, or slanted in at least a portion of the subterranean formation.

In some embodiments, the first or second fluid comprises water, gel, slickwater, hybrid fracturing fluid, viscosified aqueous fluid, acid, foam, carbon dioxide, nitrogen, hydrocarbon, polymer, sand, resin-coated proppant, ceramic proppant, proppant, or any combination thereof. In some embodiments, the first or second fluid composition changes with time. In some embodiments, the first or second fluid does not contain proppant. In some embodiments, the first or second fluid contains proppant only during certain times in the injection process.

In some embodiments, the first or second fluid comprises proppant and the concentration of proppant changes with time. In some embodiments, the first or second fluid also contains other additives, for example, acids, pH control agents, biocides, corrosion inhibitors, crosslinkers, breakers, anti-oxidants, buffers, viscosifiers, polymers, biopolymers, guar gum, high-molecular weight polysaccharides, hydroxy-ethyl-cellulose, poly-saccharides, polyacrylamide, copolymers, crosslink polymers, xanthan gum, alcohol, surfactants, viscoelastic surfactants, cationic surfactants, anionic surfactants, zwitterionic surfactants, amphoteric surfactants, and/or fluid loss additives.

In some embodiments, the first or second fluid is an energized fluid or foam comprising carbon dioxide, nitrogen, air, hydrocarbons or any combination thereof. In some embodiments, the first or second fluid further comprises surfactants. In some embodiments, the first or second fluid comprises proppant such as sand, ceramic proppant, resin-coated proppant, pre-cured resin coated, or bauxite. In some embodiments, the concentration of the proppant in the first or second fluid is in the range of from 0 kg/L to 1 kg/L. In some embodiments, the concentration of the proppant in the first or second fluid is greater than 1 kg/L.

In some embodiments, proppant is injected into the formation at 0 pounds per foot (lateral foot along the wellbore), at greater than 500 pounds per foot, at greater than 5,000 pounds per foot. In some embodiments, proppant is injected into the formation at less than 500 pounds per foot, or less than 5,000 pounds. Proppant is generally understood by one skilled in the art, for example, it is a material with an average particle size ranging from about 100 micro-meters to about 1 cm. Proppant sizes, in some embodiments, are 100 mesh, 30/50 mesh, 40/60 mesh, 20/40 mesh, 8/20 mesh.

In some embodiments, the first or second fluid comprises a breaker such as metal chelators, enzymes, oxidative breakers, pH modifiers, polymers or other micelle destabilizing chemicals or materials.

Also disclosed herein is a non-transient computer-readable medium including instructions that, when executed by one or more processors, causes the one or more processors to perform a method, the method comprising: (a) placing a first wellbore in the subterranean formation; (b) injecting a first fluid through the first wellbore into the subterranean formation at a pressure equal to or greater than the minimum horizontal stress in at least a portion of the formation; (c) creating a hydraulic fracture in the subterranean formation; (d) subsequently producing hydrocarbons through the first wellbore for a duration of time D0; (e) subsequently injecting a second fluid through the first wellbore into the subterranean formation at an injection rate of R1; (f) subsequently at a time T1 injecting the second fluid through the first wellbore into the subterranean formation at an injection rate of R2, wherein the injection rate R2 is less than 50% of the injection rate R1; (g) subsequently injecting the second fluid through the first wellbore into the subterranean formation at an injection rate less than or equal to R2 for a duration of time D1; and (h) subsequently injecting the second fluid through the first wellbore into the subterranean formation at an injection rate of R3, wherein the injection rate R3 is greater than 150% of the injection rate R2.

In an embodiment, a non-transient computer-readable medium contains instructions that, when executed by one or more processors, causes the one or more processors to perform a method, the method comprising: placing a first wellbore in the subterranean formation; injecting a first fluid through the first wellbore into the subterranean formation at a pressure equal to or greater than the minimum horizontal stress in at least a portion of the formation; creating a hydraulic fracture in the subterranean formation; producing hydrocarbons through the first wellbore for a duration of time D0; injecting a second fluid through the first wellbore into the subterranean formation at an injection rate of R1; at a time T1 injecting the second fluid through the first wellbore into the subterranean formation at an injection rate of R2, wherein the injection rate R2 is less than 50% of the injection rate R1; injecting the second fluid through the first wellbore into the subterranean formation at an injection rate less than or equal to R2 for a duration of time D1; and injecting the second fluid through the first wellbore into the subterranean formation at an injection rate of R3, wherein the injection rate R3 is greater than 150% of the injection rate R2. The method executed by said one or more processors instructed by the non-transient computer-readable medium includes all the features and combinations of the methods as discussed herein.

Advantages. There are numerous advantages of the method described herein. First, operationally this method is easy to execute in the field real-time as injection rate is the most easily controlled parameter during hydraulic fracturing treatments or fluid injection treatments into a wellbore. Second, the method is low cost as no new material needs to be introduced into the wellbore to achieve diversion. Furthermore, third, the approach is more reliable at improving fluid distribution than alternatives. For instance, it has a higher propensity to improve fluid distribution along the lateral more consistently than introducing a diverter material, which can actually worsen fluid distribution along the lateral by blocking of perforations taking less fluid and increasing fluid injection into perforations that are already taking a disproportionally large amount of fluid. Fourth, the improvements in oil production seen with the method discussed herein exceed those observed with other techniques targeted at improving fluid distribution along the wellbore. Fifth, the method described herein can be used with a broad range of completions designs. Sixth, the method described herein can be better controlled and tailored to achieve the desired result than alternative methods targeted at improving fluid distribution. For instance, alternative technologies, such as introducing diverter material into the well, can be difficult to control. Sometimes introduction of diverter material results in a screen-out and an inability to finish pumping the target volume of fluid into a well. The method described herein does not increase the potential for a screen-out and is more controllable and lower risk than alternative methods.

In this disclosure, the features as discussed herein are combinable unless otherwise specified. All such combinations are within the scope of this disclosure. Unless particularly specified, the elements or steps in a process do not have implications regarding sequence or order of said elements or steps, meaning that all combinations of sequences are contemplated to be within the scope of this disclosure.

Referring to FIGS. 5A-5C and FIG. 1, illustrations of a first wellbore and a second wellbore in a subterranean formation are presented. FIGS. 5A-5C are plan view. FIG. 1 is a cross-sectional view. In FIG. 5A, 504 represents first wellbore; 502 represents second wellbore; 506 represents hydraulic fractures; 508 represents heel side of first wellbore; 510 represents toe side of first wellbore; 512 represents downhole pressure gauge. In FIG. 5B, 524 represents first wellbore; 522 represents second wellbore; 526 represents hydraulic fractures; 528 represents heel side of first wellbore; 530 represents toe side of first wellbore; 532 represents surface wellhead pressure gauge; 534 represents bridge plug. In FIG. 5C, 544 represents first wellbore; 542 represents second wellbore; 546 represents hydraulic fractures; 548 represents heel side of first wellbore; 550 represents toe side of first wellbore; 552 represents surface wellhead pressure gauge.

Referring to FIG. 6, an illustration of fracture distribution and reservoir coverage in two adjacent horizontal hydraulically refractured wells using traditional completions approaches (plan view) is presented. In FIG. 6, 604 represents first wellbore; 602 represents second wellbore; 606 represents hydraulic fractures.

Referring to FIG. 7, an illustration of injection rate profile during hydraulic fracturing of a multi-cluster stage is presented, according to an embodiment of the method disclosed herein. In FIG. 7, 718 represents time TT1; 720 represents time TT2; 730 represents duration D1; 722 represents rate R1; 724 represents rate R2; 726 represents rate R3.

Referring to FIG. 4A, an illustration of fluid distribution across a stage during hydraulic fracturing of a multi-cluster horizontal well (cross-sectional view) is presented, according to an embodiment of this disclosure. In FIG. 4A, 402 represents heel of stage; 404 represents toe of stage; 406 represents perforation cluster 1; 408 represents perforation cluster 2; 410 represents perforation cluster 3; 412 represents perforation cluster 4; 414 represents volume of fluid injected into the formation per lateral foot along the well at time TT1; 416 represents volume of fluid injected into the formation per lateral foot along the well at time TT2.

Referring to FIG. 8, an illustration of fracture distribution and reservoir coverage in two adjacent horizontal hydraulically refractured wells (plan view) is presented, according to an embodiment of this disclosure. In FIG. 8, 804 represents first wellbore; 802 represents second wellbore; 806 represents hydraulic fractures.

Referring to FIGS. 9A-9C, illustration of pressure measurement in the second wellbore while forming a fracture in the first wellbore is presented, according to an embodiment of this disclosure. In FIGS. 9A-9C, 902 represents time TT1, 908 represents time TT2; 904 represents pressure P1; 910 represents pressure P2; 914 represents start time for injection of fluid into first wellbore (start of stage); 916 represents stop time for injection of fluid into first wellbore (end of stage); 918 represents first pressure signal; 920 represents second pressure signal; 906 represents slope M1; 912 represents slope M2. FIGS. 9A-9C represent three different embodiments of the relationship between the pressure measured by second wellbore pressure gauge and time.

In an embodiment, a method of completing a first wellbore in a subterranean formation is discussed. The method comprises a) placing a first wellbore in the subterranean formation; b) placing a second wellbore in the subterranean formation; c) injecting a fluid through the first wellbore into the subterranean formation wherein the fluid induces the formation of a stimulation fracture in the subterranean formation; d) measuring a first pressure signal in the second wellbore using a pressure gauge wherein the first pressure signal comprises a poroelastic pressure change induced by the formation of the stimulation fracture; e) subsequently measuring a second pressure signal in the second wellbore using a pressure gauge; f) determining a first metric in the first pressure signal at a time TT1; g) determining a second metric in the second pressure signal at a time TT2; and h) comparing the first metric with the second metric. In an embodiment, the first metric is a slope M1 of a pressure verses time curve in the first pressure signal, a pressure P1 of the first pressure signal, or any combination thereof. In an embodiment, the second metric is a slope M2 of a pressure verses time curve in the second pressure signal, a pressure P2 of the second pressure signal, or any combination thereof.

In an embodiment, the slope M2 is less than the slope M1 or the pressure P2 is less than the pressure P1; and the fluid distribution entering the subterranean formation at time TT2 is more uniform across the stage than the fluid distribution entering the subterranean formation at time TT1.

In an embodiment, the fluid injection rate into the first wellbore at time TT1 is R1, the fluid injection rate into the first wellbore at time TT2 is R3; and wherein R3 is in the range of 60%-140% of R1. In an embodiment, there is a first change in a first completion design parameter between time TT1 and time TT2 and wherein the first completion design parameter is selected from the group consisting of the fluid injection rate into the first wellbore, the fluid injection pressure in the first wellbore, the volume concentration of proppant in the fluid injected into the first wellbore, the composition of the proppant in the fluid injected into the first wellbore, the number of clusters in a stage in the first wellbore, the number of perforations in a stage in the first wellbore, the completed length of a stage in the first wellbore, the timing of introduction of a material in the fluid injected into the first wellbore, the volume of the fluid injected per stage into the first wellbore, the composition of the fluid injected into the first wellbore, and combinations thereof

In an embodiment, the fluid injection rate into the first wellbore is R2 after time TT1 but before time TT2 and wherein R2 is no more than 50% of the max of injection rate R1. In an embodiment, the fluid injected through the first wellbore into the subterranean formation at time TT1 and at time TT2 exits the first wellbore at a pressure greater than or equal to the minimum horizontal stress in at least a portion of the subterranean formation.

In an embodiment, the pressure of the fluid exiting the first wellbore into the subterranean formation at time TT2 is no less than 60% of the pressure of the fluid exiting the first wellbore into the subterranean formation at time TT1 and no greater than 140% of the pressure of the fluid exiting the first wellbore into the subterranean formation at time TT1.

In an embodiment, the first metric is not equal to the second metric and a second completion design parameter in the first wellbore is changed. In an embodiment, the first metric is not equal to the second metric and a second completion design parameter in a third well is changed. In an embodiment, the second completion design parameter is selected from the group consisting of the fluid injection rate into the first wellbore, the fluid injection pressure in the first wellbore, the volume concentration of proppant in the fluid injected into the first wellbore, the composition of the proppant in the fluid injected into the first wellbore, the number of clusters in a stage in the first wellbore, the number of perforations in a stage in the first wellbore, the completed length of a stage in the first wellbore, the timing of introduction of a material in the fluid injected into the first wellbore, the volume of the fluid injected per stage into the first wellbore, the composition of the fluid injected into the first wellbore, and combinations thereof. In an embodiment, the second completion design parameter is the fluid injection rate into the first wellbore and wherein at time TT2 the fluid injection rate into the first wellbore is R3 and wherein subsequently the fluid injection rate into the first wellbore is reduced to a rate R4 for a duration of time D2 and wherein subsequently the fluid injection rate into the first wellbore is a rate R5, wherein rate R5 is at least 50% greater than rate R4.

In an embodiment, the duration of time D1 is greater than 1 minute. In an embodiment, the duration of time D1 is from 1 minute to 30 minutes. In an embodiment, the duration of time D1 is from 5 minutes to 15 minutes. In an embodiment, the duration of time D1 is greater than 5 minutes, greater than 10 minutes, or greater than 30 minutes. In an embodiment, the duration of time D1 is less than 2 hours.

In an embodiment, no diverter material is introduced into the first wellbore between time TT2 and time TT1. In an embodiment, the heel most stage in the second wellbore is isolated from previous stages toward the toe of the second wellbore by a bridge plug.

In an embodiment, the pressure in the second wellbore is monitored using a wellhead pressure gauge, a downhole pressure gauge, a downhole retrievable pressure gauge, a downhole fiber optic gauge, or a downhole pressure gauge installed in a bridge plug. In an embodiment, the method comprises forming a monitor fracture in the second wellbore prior to step (c). In an embodiment, the monitor fracture and the stimulation fracture do not intersect.

In an embodiment, the fluid comprises water, gel, slickwater, hybrid fracturing fluid, viscosified aqueous fluid, acid, foam, carbon dioxide, nitrogen, hydrocarbon, polymer, sand, resin-coated proppant, ceramic proppant, proppant, or any combination thereof

In an embodiment, the first wellbore has two or more perforated zones. In an embodiment, at least one perforated zone in the first wellbore is not effectively treated during step (d) and wherein the at least one perforated zone that is not effectively treated during step (d) is effectively treated during step (e). Not effectively treated is typically understood as a disproportionately small amount of fluid is passing through a perforated zone. In an embodiment, the ratio of the rate of fluid injected into a first perforated zone to that into a second perforated zone in step (d) is not equal to the ratio of the rate of fluid injected into the first perforated zone to that into the second perforated zone in step (e).

In an embodiment, the method comprises recovering hydrocarbons from the subterranean formation through the first wellbore. In an embodiment, the subterranean formation is selected from the group consisting of a low permeability formation, shale formation, tight formation, ultra-tight formation, hydrocarbon-bearing formation, oil reservoir, gas reservoir, hydrocarbon reservoir, and combinations thereof

In an embodiment, step (h) is taking place while the fluid is being injected into the first wellbore. In an embodiment, the first wellbore and the second wellbore are the same wellbore.

In some embodiments, the rate of injection of the fluid through the first wellbore into the subterranean formation rate is reduced from R1 to R2 at a time T1. In some embodiments, the time T1 is determined prior to treating the stage. In some embodiments, the time T1 is approximately determined and approximately a fixed duration after starting injection treatement of the stage. In some embodiments, the time T1 occurs after a pre-determined of volume is injected into the well. In some embodiments, the time T1 is determined by monitoring fluid distribution, fracture growth rates, pressure responses or other phenomenon in the first well being stimulated or in a second well in the subterranean formation. Monitoring may be done with microseismic, fiber optics, well head pressure monitoring, downhole pressure monitoring, fluid injection rate, surface or downhole tiltmeters, or any combination thereof.

In an embodiment, R1 is varied with time or fixed. In an embodiment, R2 is varied with time or fixed. In an embodiment, R3 is varied with time or fixed. In one embodiment, R1 is greater than 20 barrels per minutes. In another embodiment, R1 is greater than 50 barrels per minutes. In another embodiment, R1 is greater than 80 barrels per minute. In one embodiment, R3 is equal to Rl. In another embodiment, the maximum of R3 is greater than 60% of the maximum of R1 and less than 140% of the maximum of R1. In one embodiment, R2 is 10 barrels per minute. In another embodiment, R2 is less than 30 barrels per minute. In another embodiment, R2 is 0 barrels per minute. In another embodiment, R4 is 10 barrels per minute. In another embodiment, R4 is less than 30 barrels per minute or 0 barrels per minute. In one embodiment, the maximum of R5 is equal to the maximum of R3. In another embodiment, the maximum of R5 is greater than the maximum of R3. In another embodiment, the maximum of R5 is greater than 60% of the maximum of R1 and less than 140% of the maximum of R1.

In an embodiment, monitoring is from a second well adjacent to the first well into which fluid is being injected. At least a portion of the subterranean formation in proximity to the second well has been hydraulically fractured prior to stimulating the first well. In an embodiment, the second well is at least partially filled with water, slickwater, gel, hybrid frac fluid, energized fluid, fracturing fluid, gas, hydrocarbon, or another fluid. The second well may have been recently completed, in the process of being completed, completed and produced for a period of time, or not yet completed. In an embodiment, the second well has one or more perforated zones. One or more stages in the second well may be isolated from previous stages (on the toe side of the well) using bridge plugs or other isolation techniques, including but not limited to cement, packers, or sliding sleeves. In an embodiment, at least a portion of the second well is within 100 feet, 500 feet, 1,000 feet, or 2,500 feet of at least a portion of the first well. At least a portion of the second wellbore or the first wellbore may be vertical, horizontal, or slanted within the formation.

In an embodiment, the duration of time D1 is about 1 minute, about 5 minutes, about 10 minutes, about 20 minutes, about 30 minutes or about 2 hours. In some embodiments, the duration of time D1 is established before the injection treatment. In some embodiments, the duration of time D1 is approximately constant. In some embodiments, the duration of time D1 varies. In some embodiments, the duration of time D1 is determined based on monitoring in the first well, the second well, or any combination thereof. During the period of injection at rate R2, in some embodiments, no diverter is injected into the first wellbore. In some embodiments, no diverter is injected into the first wellbore. In some embodiments, less than 10 lbs of diverter per gallon of fluid is injected into the first wellbore. In some embodiments less than 100 lbs of diverter per gallon of fluid is injected into the first wellbore. The controlled injection process described herein is believed to act to divert the fluid automatically to clusters which were previously not being effectively treated without the need of injecting diverting agents. Not effectively treated is typically understood as a disproportionately small amount of fluid is passing through a perforated zone.

In some embodiments, the subterranean formation is a hydrocarbon bearing formation. In some embodiments, it is an oil bearing formation, a water bearing formation, a hydrocarbon gas bearing formation, or a CO2 bearing formation. In some embodiments, the subterranean formation is a shale, a tight formation, an ultra-tight formation, a carbonate, or an unconventional play. The well test permeability of the subterranean formation in some cases is less than 10 Darcy, less than 1 mD, less than 100 micro-Darcy, less than 1 micro-Darcy, or less than 10 nano-Darcy. In some embodiments, the methods and systems as discussed herein are used during hydraulic fracturing. In some embodiments, the methods and systems as discussed herein are used during matrix treatments.

In some embodiments, the first wellbore and the second wellbore penetrating the subterranean formation are cased, cemented, open hole with external packers, and/or perforated, slotted, or jetted. In an embodiment, the first wellbore and the second wellbore are vertical, approximately horizontal, or slanted in at least a portion of the subterranean formation. In some embodiments, the first wellbore and the second wellbore are the same wellbore. For instance, this can occur when pressure is monitored in a previously completed stage that is isolated from another stage being completed in the same well, such as the case in a sliding sleeve completion with coiled tubing or in a scenario where a downhole pressure gauge or fiber line reading pressure in a previously completed stage (that is isolated from the stage being completed by a bridge plug) can be monitored real time.

In some embodiments, the first wellbore and/or the second wellbore are previously stimulated wells. In some embodiments, the first wellbore and/or the second wellbore are restimulated or refractured. In some embodiments, the stimulation treatment in the second or stimulated wellbore is a refracturing treatment.

In one embodiment, the comparison between the first metric and the second metric is done in semi-real-time. Semi-real-time is defined as a time period of interest deemed short enough to enable decisions pertinent to the current process. In some embodiments, semi-real-time is within 5 minutes. In other embodiments, semi-real-time is within 30 minutes or 3 hours. In other embodiments, semi-real-time is prior to completion of the next stage. In some embodiments, semi-real-time is prior to completion of the next well to be completed. In another embodiment, the comparison between the first metric and the second metric is done while the fluid is being injected into the first wellbore. In another embodiment, the comparison between the first metric and the second metric is done while fracturing the same stage in the first wellbore.

In some embodiments, the fluid comprises water, gel, slickwater, hybrid fracturing fluid, viscosified aqueous fluid, acid, foam, carbon dioxide, nitrogen, hydrocarbon, polymer, sand, resin-coated proppant, ceramic proppant, proppant, or any combination thereof. In some embodiments, the fluid does not contain proppant or contains proppant only during certain times in the injection process. In some embodiments, the fluid comprises proppant and the concentration of proppant changes with time. The fluid may also contain other additives. Many additives are typically used in hydraulic fracturing fluids, such as, pH control agents, biocides, corrosion inhibitors, crosslinkers, breakers, anti-oxidants, buffers, viscosifiers, polymers, biopolymers, guar gum, high-molecular weight polysaccharides, hydroxy-ethyl-cellulose, poly-saccharides, polyacrylamide, copolymers, crosslink polymers, xanthan gum, alcohol, surfactants, viscoelastic surfactants, cationic surfactants, anionic surfactants, zwitterionic surfactants, amphoteric surfactants, and/or fluid loss additives, etc.

In some embodiments, the fluid is an energized fluid or foam comprising carbon dioxide, nitrogen, air, hydrocarbons or any combination thereof. In an embodiment, the fluid further comprises surfactant. In an embodiment, the fluid further comprises proppant such as sand, ceramic proppant, resin-coated proppant, pre-cured resin coated, or bauxite. In an embodiment, the concentration of the proppant in the fluid ranges from 0 kg/L to 1 kg/L. In an embodiment, the concentration of the proppant in the fluid is outside of this range. In an embodiment, proppant is injected into the formation at 0 pounds per foot (lateral foot along the wellbore). In an embodiment, proppant is injected into the formation at greater than or less than 500 pounds per foot, or sometimes greater than or less than 5,000 pounds per foot or anywhere in between. Proppant is generally understood by one skilled in the art but it can be material with the average particle size ranging from about 100 micro-meters to about 1 cm. Proppant sizes, in some embodiments, are 100 mesh, 30/50 mesh, 40/60 mesh, 20/40 mesh, 8/20 mesh. In an embodiment, the fluid further comprises a breaker such as metal chelators, enzymes, oxidative breakers, pH modifiers, polymers or other micelle destabilizing chemicals or materials.

In one embodiment, the first metric and the second metric are compared in real-time. In another embodiment, the first metric and the second metric are compared while the fluid is being injected into the first wellbore. In one embodiment, software is used to compare the first metric to the second metric, and a recommendation on future action is given. In one embodiment, the recommendation on future actions comprises recommending a change in the completions procedure. In one embodiment, the change in completions procedure is a change in the stage being pumped into the first wellbore in which both the first and second pressure signals are measured. In another embodiment, the change in completions procedure is in a different stage or different well. A change in completions procedure includes but is not limited to a change in pump rate schedule, a change in proppant schedule or design, a change in injection pressure, a change in injection duration, a change in injection volume, a change in injection rate, a chance in composition of the injected fluid, a change in composition of the proppant, a change in order of well completions, a change in well landing depth, a change in number of stages per well, a change in stage spacing, a change in number of clusters or perforations per stage, a change in timing of introduction of proppant, a change in diverter drop size, a change in diverter drop timing, a change in diverter drop concentration, a change in the fluid phase injected into the wellbore upon a change in proppant concentration, mesh size, material, or design, or any combination thereof.

In one embodiment, when the slope M2 is less than the slope M1, the fluid distribution along the first wellbore is improved. In another embodiment, when the slope M2 is less than the slope Ml, and the injection pressure of the fluid leaving the first wellbore at time TT1 is approximately equal to that at time TT2, the fluid distribution along the first wellbore is improved. In another embodiment, when the slope M2 is less than the slope M1, and the injection pressure of the fluid leaving the first wellbore at time TT2 is greater than 60% of that at time TT1 and less than 140% of that at time TT1, the fluid distribution along the first wellbore is improved. In another embodiment, when the slope M2 is less than the slope M1, and the rate of fluid injection into the first wellbore at time TT1 is approximately equal to that at time TT2, the fluid distribution along the first wellbore is improved. In another embodiment, when the slope M2 is less than the slope M1, and the rate of fluid injection into the first wellbore at time TT2 is greater than 60% of that at time TT1 and less than 140% of that at time TT1, the fluid distribution along the first wellbore is improved.

In one embodiment, when the pressure P2 in the second wellbore is less than the pressure P1 in the second wellbore, the fluid distribution along the first wellbore is improved. In another embodiment, when the pressure P2 is less than the pressure P1, and the injection pressure of the fluid leaving the first wellbore at time TT1 is approximately equal to that at time TT2, the fluid distribution along the first wellbore is improved. In another embodiment, when the pressure P2 is less than the pressure P1, and the injection pressure of the fluid leaving the first wellbore at time TT2 is greater than 60% of that at time TT1 and less than 140% of that at time TT1, the fluid distribution along the first wellbore is improved. In another embodiment, when the pressure P2 is less than the pressure P1, and the rate of fluid injection into the first wellbore at time TT1 is approximately equal to that at time TT2, the fluid distribution along the first wellbore is improved. In another embodiment, when the pressure P2 is less than the pressure P1, and the rate of fluid injection into the first wellbore at time TT2 is greater than 60% of that at time TT1 and less than 140% of that at time TT1, the fluid distribution along the first wellbore is improved.

In an embodiment, time TT1 occurs in a first stage and time TT2 occurs in a second stage. In an embodiment, the first stage and the second stage are the same stage or different stages.

A “poroelastic pressure change induced by the formation of a stimulation fracture” as used herein is a pressure change in the fluid in the second wellbore that is measured by the pressure gauge and is a result of a change in stress in the subterranean formation caused by the formation of the stimulation fracture. A poroelastic response is one induced by displacement of a solid. For instance, when a stimulated fracture is forming it applies a pressure to the rock matrix or formation. If this pressure is different from the natural reservoir pressure in the formation, then it will cause a strain or displacement of the formation. This applied pressure from the stimulated fracture also results in a change in the Dirichlet stress boundary condition. These changes result in changes in the stress field in the formation. A change in the stress field in the formation near an observation fracture will result in a change in the fluid pressure in the observation fracture. This phenomenon is distinctly different from a change in fluid pressure due to direct fluid communication. Direct fluid communication can occur when fluids are in direct physical contact as in where the observation fracture and the stimulated fracture intersect. Direct fluid communication can also occur when the observation fracture and stimulated fracture are both in contact with a high permeability pathway, such as the fluid in a wellbore. In the case of ultra-tight formations, the permeability is very low, often less than 1 millidarcy and sometimes less than 1 microdarcy. Provided there is no direct connectivity between a first fracture in a second wellbore and a second fracture in a first wellbore, and the two fractures are separated by an ultra-tight formation, the fluids in the two fractures would not be considered in fluid communication.

Poroelastic pressure changes in a monitor well as a result of hydraulic fracturing an adjacent well are often less than 1 to 10 psi in magnitude. In some cases, they can be 10 to 100 psi or even greater than 100 psi when the stimulation fracture is in very close proximity to the observation fracture.

Also disclosed herein is a non-transient computer-readable medium containing instructions that, when executed by one or more processors, causes the one or more processors to perform a method, the method comprising: a) placing a first wellbore in the subterranean formation; b) placing a second wellbore in the subterranean formation; c) injecting a fluid through the first wellbore into the subterranean formation wherein the fluid induces the formation of a stimulation fracture in the subterranean formation; d) measuring a first pressure signal in the second wellbore using a pressure gauge wherein the first pressure signal comprises a poroelastic pressure change induced by the formation of the stimulation fracture; e) subsequently measuring a second pressure signal in the second wellbore using a pressure gauge; f) determining a first metric in the first pressure signal at a time TT1; g) determining a second metric in the second pressure signal at a time TT2; and h) comparing the first metric with the second metric.

In an embodiment, the first metric is a slope M1 of a pressure verses time curve in the first pressure signal, a pressure P1 of the first pressure signal, or any combination thereof and the second metric is a slope M2 of a pressure verses time curve in the second pressure signal, a pressure P2 of the second pressure signal, or any combination thereof. In an embodiment, the slope M2 is less than the slope M1 or the pressure P2 is less than the pressure P1; and the fluid distribution entering the subterranean formation at time TT2 is more uniform across the stage than the fluid distribution entering the subterranean formation at time TT1.

In an embodiment, the fluid injection rate into the first wellbore at time TT1 is R1, the fluid injection rate into the first wellbore at time TT2 is R3 and wherein R3 is in the range of 60%-140% of Rl.

In an embodiment, there is a first change in a first completion design parameter between time TT1 and time TT2 and wherein the completion design parameter is selected from the group consisting of the fluid injection rate into the first wellbore, the fluid injection pressure in the first wellbore, the volume concentration of proppant in the fluid injected into the first wellbore, the composition of the proppant in the fluid injected into the first wellbore, the number of clusters in a stage in the first wellbore, the number of perforations in a stage in the first wellbore, the completed length of a stage in the first wellbore, the timing of introduction of a material in the fluid injected into the first wellbore, the volume of the fluid injected per stage into the first wellbore, the composition of the fluid injected into the first wellbore, and combinations thereof

In an embodiment, the fluid injection rate into the first wellbore is R2 after time TT1 but before time TT2 and wherein R2 is no more than 50% of the max of injection rate Rl. In an embodiment, the fluid injected through the first wellbore into the subterranean formation at time TT1 and at time TT2 exits the first wellbore at a pressure greater than or equal to the minimum horizontal stress in at least a portion of the subterranean formation.

In an embodiment, the pressure of the fluid exiting the first wellbore into the subterranean formation at time TT2 is no less than 60% of the pressure of the fluid exiting the first wellbore into the subterranean formation at time TT1 and no greater than 140% of the pressure of the fluid exiting the first wellbore into the subterranean formation at time TT1.

In an embodiment, time TT1 occurs in a first stage and time TT2 occurs in a second stage. In an embodiment, the first stage and the second stage are the same stage or different stages.

In an embodiment, the first metric is not equal to the second metric and a second completion design parameter in the first wellbore is changed. In an embodiment, the first metric is not equal to the second metric and a second completion design parameter in a third well is changed.

In an embodiment, the second completion design parameter is selected from the group consisting of the fluid injection rate into the first wellbore, the fluid injection pressure in the first wellbore, the volume concentration of proppant in the fluid injected into the first wellbore, the composition of the proppant in the fluid injected into the first wellbore, the number of clusters in a stage in the first wellbore, the number of perforations in a stage in the first wellbore, the completed length of a stage in the first wellbore, the timing of introduction of a material in the fluid injected into the first wellbore, the volume of the fluid injected per stage into the first wellbore, the composition of the fluid injected into the first wellbore, and combinations thereof

In an embodiment, the second completion design parameter is the fluid injection rate into the first wellbore and wherein at time TT2 the fluid injection rate into the first wellbore is R3 and wherein subsequently the fluid injection rate into the first wellbore is reduced to a rate R4 for a duration of time D2 and wherein subsequently the fluid injection rate into the first wellbore is a rate R5, wherein rate R5 is at least 50% greater than rate R4.

In an embodiment, the duration of time D1 is greater than 1 minute. In an embodiment, the duration of time D1 is from 1 minute to 2 hours. In an embodiment, the duration of time D1 is from 5 minutes to 30 minutes.

In an embodiment, no diverter material is introduced into the first wellbore between time TT2 and time TT1. In an embodiment, the method comprises forming a monitor fracture in the second wellbore prior to step (c). In an embodiment, the monitor fracture and the stimulation fracture do not intersect.

In an embodiment, the first wellbore has at least two perforated zones and wherein at least one perforated zone in the first wellbore is not effectively treated during step (d) and wherein the at least one perforated zone that is not effectively treated during step (d) is effectively treated during step (e). In an embodiment, the first wellbore has at least two perforated zones and wherein the ratio of the rate of fluid injected into a first perforated zone to that into a second perforated zone in step (d) is not equal to the ratio of the rate of fluid injected into the first perforated zone to that into the second perforated zone in step (e).

In an embodiment, the method comprises recovering hydrocarbons from the subterranean formation through the first wellbore. In an embodiment, step (h) is taking place while the fluid is being injected into the first wellbore.

The method executed by said one or more processors instructed by the non-transient computer-readable medium includes all the features and combinations of the methods as discussed herein.

Herein also disclosed is a system for completing a first wellbore in a subsurface formation, comprising: a first wellbore in the subterranean formation; a second wellbore in the subterranean formation; a first fracture configured to be formed in pressure communication with the second wellbore; a second fracture configured to be formed in pressure communication with the first wellbore; a pressure gauge in pressure communication with the fluid in the second wellbore; a computer processor coupled to the pressure gauge, wherein the computer processor is configured to determine a first metric in a first pressure signal from the pressure gauge at time TT1 while the second fracture is being formed and to determine a second metric in a second pressure signal from the pressure gauge at time TT2, wherein the first pressure signal comprises a poroelastic pressure change induced by the formation of the second fracture, and wherein the computer processor is configured to compare the first metric with the second metric.

In an embodiment, time TT1 occurs in a first stage and time TT2 occurs in a second stage. In an embodiment, the first stage and the second stage are the same stage or different stages.

In various embodiments, the recovery of hydrocarbons using the instant methods and systems is uplifted by 10% or more. In various embodiments, the recovery of hydrocarbons using the instant methods and systems is uplifted by 20% or more. In various embodiments, the recovery of hydrocarbons using the instant methods and systems is uplifted by 30% or more. In various embodiments, the recovery of hydrocarbons using the instant methods and systems is uplifted by 40% or more. In various embodiments, the recovery of hydrocarbons using the instant methods and systems is uplifted by 50% or more. In various embodiments, the recovery of hydrocarbons using the instant methods and systems is uplifted by 60% or more. In various embodiments, the recovery of hydrocarbons using the instant methods and systems is uplifted by 70% or more. In various embodiments, the recovery of hydrocarbons using the instant methods and systems is uplifted by 80% or more. In various embodiments, the recovery of hydrocarbons using the instant methods and systems is uplifted by 90% or more. In various embodiments, the recovery of hydrocarbons using the instant methods and systems is uplifted by 100% or more.

Advantages. There are numerous advantages of the method described herein. First, operationally this method is easy to execute in the field real-time. Second, the method is low cost as no expensive downhole diagnostic equipment is required for the method. Furthermore, third, the approach is more reliable at evaluating and improving fluid distribution than alternatives. Fourth, the improvements in oil production seen with the method discussed herein exceed those observed with other techniques targeted at improving fluid distribution along the wellbore. Fifth, the method described herein can be used with a broad range of completions designs. Sixth, the method described herein presents a lower risk to operations. For instance, other technologies often introduce equipment downhole in the well or involve complex operational procedures either of which can increase the risk of operations and the cost of operations in the event of an unexpected situation.

EXAMPLES Example 1

To facilitate a better understanding of the invention, the following example is given. In no way should the following example be read to limit or define the scope of the invention.

In an embodiment, a multi-stage horizontal well in an u1tra-tight oil formation was hydraulically fractured. Fluid distribution along the well was being monitored during the treatment of a stage. More than 50% of the fluid was entering the formation through the two clusters nearest the heel in the stage while less than 50% of the fluid was entering the four clusters nearest the toe of the stage. The injection rate was reduced by more than 80% for approximately 5 minutes to 30 minutes. The injection rate was subsequently increased to within 20% of the injection rate prior to the rate reduction. It was surprisingly discovered that the fluid distribution across the stage was substantially improved. The rate cycling strategy was repeated multiple times in the stage, and in subsequent stages. The rate cycling strategy was further repeated in every stage of a new well in proximity to a well completed with the same number of stages and the same pumped fluid and proppant volume. The new well using the rate cycling strategy unexpectedly demonstrated an increase in early time oil production rates by more than 100% over the well without the rate cycling strategy even though the overall completions costs between the two wells were comparable.

Example 2

In an embodiment, a third multi-stage horizontal well in an ultra-tight oil formation was hydraulically fractured and produced for several years. The third well was then restimulated to improve production, Production from the restimulated well was observed to be only slightly improved over production prior to the restimulation. A fourth multi-stage horizontal well in an ultra-tight oil formation was hydraulically fractured and produced for several years. The fourth well was then restimulated to improve production and mitigate the risk of fracturing into the depleted zone with new wells that were being completed after the restimulation process. Fluid distribution along the well was being monitored during the restimulation of the well. Prior to refracturing fluid was injected at low rate at a pressure below the initial minimum horizontal stress of the formation for an extended period of time. This injection period was believed to increase the pressure in all of the fractures along the lateral. The fourth well was then restimulated with fluid injected into the well at a pressure greater than the minimum horizontal stress in at least a portion of the subterranean formation. Several injection rate cycles were used where the injection rate was very high for a period of time, then subsequently the rate was decreased for a period of time, then subsequently the rate was increased again for a period of time, This rate cycling was repeated several times, During the rate reductions, the injection rate was reduced by more than 80%. It has been surprisingly discovered that the fluid distribution along the well was substantially improved over what is typically observed in more conventional restimulation processes. The production increase of the restimulated fourth well over its production prior to restimulation. was significant and much better than that of the first well, which applied a more conventional restimulation process.

Example 3

In an embodiment, a multi-stage horizontal monitor well in an ultra-tight oil formation was hydraulically fractured. A wellhead pressure gauge was installed on the monitor well. A second multi-stage horizontal stimulation well was then hydraulically fractured. Fiber optics and microseismic were used to monitor fluid distribution along the stimulation well. During stimulation of the stimulation well, the pressure in the monitor well was also monitored.

After a period of time, the growth of fractures, particularly the growth of the largest fracture, in the stimulation well induced a poroelastic pressure response in the monitor well. The slope of the poroelastic pressure response in the monitor well was determined. The fluid injection rate into the stimulation well was reduced by more than 80% for approximately 5 to 30 minutes. The fluid injection rate into the stimulation well was then increased to approximately the same injection rate used prior to the rate reduction. The slope of the poroelastic pressure response in the monitor well was then again determined after returning to a similar injection rate. The fluid distribution across the stage was determined to be substantially improved after returning to approximately the initial injection rate after the rate reduction based on fiber optics and microseismic measurements.

It has been surprisingly discovered that the slope of the poroelastic pressure response in the monitor well after the rate reduction was reduced relative to the slope prior to the rate reduction, despite similar injection rates before and after the rate reduction. This process was repeated multiple times in several stages. It was also discovered that in cases where the fluid distribution changed more based on fiber optics and microseismic, the change in slope of the poroelastic pressure response before and after the rate reduction was greater. Furthermore, a subsequent well completed with substantially fewer stages at a significantly lower cost also demonstrated improved fluid distribution along the lateral. Thus, the method and system of this disclosure demonstrated surprisingly attractive oil production rates with substantial savings in completions costs.

This disclosure is an illustrative example and thereof it can be readily appreciated by those skilled in the art that various changes in the details of the illustrated construction or combinations of the elements described herein can be made without departing from the spirit of the instant invention.

While preferred embodiments of the invention have been shown and described, modifications thereof can be made by one skilled in the art without departing from the spirit and teachings of the invention. The embodiments described herein are some only, and are not intended to be limiting. Many variations and modifications of the invention disclosed herein are possible and are within the scope of the invention. Where numerical ranges or limitations are expressly stated, such express ranges or limitations should be understood to include iterative ranges or limitations of like magnitude falling within the expressly stated ranges or limitations (e.g., from about 1 to about 10 includes, 2, 3, 4, etc.; greater than 0.10 includes 0.11, 0.12, 0.13, and so forth). Use of the term “optionally” with respect to any element of a claim is intended to mean that the subject element is required, or alternatively, is not required. Both alternatives are intended to be within the scope of the claim. Use of broader terms such as comprises, includes, having, etc. should be understood to provide support for narrower terms such as consisting of, consisting essentially of, comprised substantially of, and the like.

Accordingly, the scope of protection is not limited by the description set out above but is only limited by the claims which follow, that scope including all equivalents of the subject matter of the claims. The elements in the claims below are not any particular order unless otherwise specified. Each and every claim is incorporated into the specification as an embodiment of the present invention. Thus, the claims are a further description and are an addition to the preferred embodiments of the present invention. The disclosures of all patents, patent applications, and publications cited herein are hereby incorporated by reference, to the extent they provide some, procedural or other details supplementary to those set forth herein. 

1. A method of injecting a fluid into a subterranean formation, the method comprising: (a) placing a first wellbore in the subterranean formation; (b) injecting the fluid through the first well bore into the subterranean formation at an injection rate of R1, wherein the fluid enters the subterranean formation at a pressure greater than or equal to the minimum horizontal stress in at least a portion of the subterranean formation; (c) subsequently at a time T1 injecting the fluid through the first wellbore into the subterranean formation at an injection rate of R2, wherein the injection rate R2 is no greater than 50% of the injection rate R1 and no less than 5% of the injection rate R1; (d) subsequently injecting the fluid through the first wellbore into the subterranean formation at an injection rate less than or equal to R2 for a duration of time D1; and (e) subsequently injecting the fluid through the first wellbore into the subterranean formation at an injection rate of R3, wherein the fluid enters the subterranean formation at a pressure greater than or equal to the minimum horizontal stress in at least a portion of the subterranean formation, wherein the injection rate R3 is no less than 150% of the injection rate R2.
 2. The method of claim 1, wherein the fluid comprises water, gel, slickwater, hybrid fracturing fluid, viscosified aqueous fluid, acid, foam, carbon dioxide, nitrogen, hydrocarbon, polymer, sand, resin-coated proppant, ceramic proppant, or proppant.
 3. The method of claim 1 comprising changing the composition of the fluid.
 4. The method of claim 1, wherein the fluid does not comprise diverter material during step (d).
 5. The method of claim 1, wherein the duration of time D1 is no less than 30 seconds, or no less than 5 minutes, or no less than 10 minutes, or no less than 30 minutes, or no greater than 3 hours.
 6. The method of claim 1, wherein steps (c)-(e) are repeated.
 7. The method of claim 1, wherein the injection rate R1 is greater than or equal to 20 barrels per minute.
 8. The method of claim 1, wherein the injection rate R2 is greater than or equal to 1 barrels per minute.
 9. The method of claim 1, wherein the first well bore has two or more perforated zones.
 10. The method of claim 9, wherein the ratio of the rate of fluid injected into a first perforated zone over the rate of fluid injected into a second perforated zone is Rr and Rr is less than 1 during step (b), wherein Rr during step (e) is greater than Rr during step (b).
 11. The method of claim 1 comprising recovering hydrocarbons from the subterranean formation through the first well bore.
 12. The method of claim 1, wherein the subterranean formation is selected from the group consisting of a low permeability formation, shale formation, tight formation, ultra-tight formation, hydrocarbon-bearing formation, oil reservoir, gas reservoir, or hydrocarbon reservoir, and combinations thereof
 13. The method of claim 1, wherein the subterranean formation is hydraulically fractured.
 14. The method of claim 1 comprising placing a second wellbore penetrating the subterranean formation and monitoring the second well bore to determine time T1.
 15. The method of claim 14, wherein the fluid pressure in the second well bore is measured.
 16. The method of claim 15, wherein at least a portion of the subterranean formation in contact with the second well bore has been hydraulically fractured.
 17. The method of claim 15, wherein the fluid pressure in the second wellbore is measured using a wellhead pressure gauge, a downhole pressure gauge, a downhole retrievable pressure gauge, a downhole fiber optic gauge, or a downhole pressure gauge installed in a bridge plug.
 18. A method of injecting a fluid into a subterranean formation, the method comprising: placing a first well bore in the subterranean formation; injecting the fluid through the first wellbore into the subterranean formation at an injection rate of R1, wherein R1 is varied with time or fixed; injecting the fluid through the first wellbore into the subterranean formation at an injection rate of R2 for a duration of time D1, wherein R2 is varied with time or fixed and R2 is in the range of 5%-50% of the max of injection rate R1; and injecting the fluid through the first wellbore into the subterranean formation at an injection rate of R3, wherein R3 is varied with time or fixed and wherein the max of injection rate R3 is no less than 150% of the minimum of injection rate R2.
 19. The method of claim 19 wherein the fluid enters the subterranean formation at a pressure greater than or equal to the minimum horizontal stress in at least a portion of the subterranean formation when the fluid is injected at injection rate of R1 or R3.
 20. A non-transient computer-readable medium including instructions that, when executed by one or more processors, causes the one or more processors to perform a method, the method comprising: placing a first well bore in the subterranean formation; injecting the fluid through the first wellbore into the subterranean formation at an injection rate of R1, wherein R1 is varied with time or fixed; injecting the fluid through the first wellbore into the subterranean formation at an injection rate of R2 for a duration of time D1, wherein R2 is varied with time or fixed and R2 is in the range of 5%-50% of the max of injection rate R1; and injecting the fluid through the first wellbore into the subterranean formation at an injection rate of R3, wherein R3 is varied with time or fixed and wherein the max of injection rate R3 is no less than 150% of the minimum of injection rate R2. 